UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
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x
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Annual
Report Pursuant To Section 13 or 15(d) of The Securities Exchange
Act of
1934
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For
The Fiscal Year Ended December 31, 2006
OR
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Transition
Report Pursuant To Section 13 Or 15(d) of The Securities Exchange
Act of
1934
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Commission
File Number: 000-51801
ROSETTA
RESOURCES INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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43-2083519
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(State
or other jurisdiction of incorporation or
organization)
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(I.R.S.
Employer Identification No.)
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717
Texas, Suite 2800, Houston, TX
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77002
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(Address
of principal executive offices)
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(Zip
Code)
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Registrant's
telephone number, including area code: (713)
335-4000
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Securities Registered Pursuant to Section 12(b) of the Act:
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Common
Stock, $.001 Par Value
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The
Nasdaq Stock Market LLC
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(Title
of Class)
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(Name
of Exchange on which registered)
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Securities
Listed Pursuant to Section 12 (g) of the Act:
None
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined
in
Rule 405 of the Securities Act of 1933. Yes ¨
Nox
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ¨
Nox
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 if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of the registrant’s knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to
this
Form 10-K. x
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
aggregate market value of the voting and non-voting common equity held by
non-affiliates of the registrant as of June 30, 2006 was approximately $831
million based on the closing price of $16.62 per share on the Nasdaq Global
Select Market.
The
number of shares of the registrant’s Common Stock, $.001 par value per share
outstanding as of March 5, 2007 was 50,753,951.
Documents
Incorporated By Reference
Information
required by Part III will either be included in Rosetta Resources Inc.’s definitive
proxy
statement filed with the Securities and Exchange Commission or filed as an
amendment to this Form 10-K no later than 120 days after the end of the
Company’s fiscal year, to the extent required by the Securities Exchange Act of
1934, as amended.
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Table
of Contents
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Page
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Part
I -
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3
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13
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23
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23
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24
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26
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Part
II -
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27
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28
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29
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47
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49
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89
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89
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90
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Part
III -
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91
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91
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91
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91
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91
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Part
IV -
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92
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Cautionary
Note
This
Annual Report contains forward-looking statements of our management regarding
factors that we believe may affect our performance in the future. Such
statements typically are identified by terms expressing our future expectations
or projections of revenues, earnings, earnings per share, cash flow, market
share, capital expenditures, effects of operating initiatives, gross profit
margin, debt levels, interest costs, tax benefits and other financial items.
All
forward-looking statements, although made in good faith, are based on
assumptions about future events and are, therefore, inherently uncertain; and
actual results may differ materially from those expected or projected. Important
factors that may cause our actual results to differ materially from expectations
or projections include those described under the heading “Forward-Looking
Statements” in Item 7. Forward-looking statements speak only as of the date
of this report, and we undertake no obligation to update or revise such
statements to reflect new circumstances or unanticipated events as they
occur.
For
a
glossary of oil and natural gas terms, see page 97.
General
Rosetta
Resources Inc. (together with our consolidated subsidiaries, the “Company”) was
formed in June 2005 to acquire Calpine Natural Gas L.P. the domestic oil and
natural gas business formerly owned by Calpine Corporation and affiliates
(“Calpine”). The Company (“Successor”) acquired Calpine Natural Gas L.P.
(“Predecessor”) in July 2005 (hereinafter, the “Acquisition”) and together with
all subsequently acquired oil and gas properties is engaged in oil and natural
gas exploration, development, production and acquisition activities in the
United States and operates in one business segment. Our operations are primarily
concentrated in the Sacramento Basin of California, the Lobo and Perdido Trends
in South Texas, the State Waters of Texas, the Gulf of Mexico and the Rocky
Mountains. The Company has grown its existing property base through exploitation
of its leasehold acreage and by: purchasing new undeveloped leases; acquiring
oil and gas producing properties from third parties; and acquiring drilling
prospects with third parties where the Company earns an ownership interest
in
new third party properties or otherwise participates in
exploration.
Pursuant
to the Acquisition, we entered into several operative contracts with Calpine,
including a purchase and sale agreement (together with the interrelated
agreements concurrently executed on or about July 7, 2005, are hereinafter,
collectively, the “Purchase Agreement”) under which we have indemnification
rights and obligations with respect to Calpine. Currently, Calpine markets
our
oil and gas under a marketing services agreement whose term runs through June
30, 2007. We also sell a significant portion of our gas to Calpine pursuant
to
certain gas purchase and sales contracts, all of which were part of the
Acquisition documents.
In
October 1999, Calpine purchased Sheridan Energy, Inc. (“Sheridan”), a natural
gas exploration and production company operating in northern California and
the
Gulf Coast region. Sheridan, renamed Calpine Natural Gas Company, provided
the
initial management team an operational infrastructure to evaluate and acquire
oil and natural gas properties for Calpine. In December 1999, Calpine purchased
Vintage Petroleum, Inc.’s interest in the Rio Vista Gas Unit and related areas,
representing primarily natural gas reserves located in the Sacramento Basin
in
northern California. In October 2001, Calpine Natural Gas Company completed
the
acquisition of 100% of the voting stock of Michael Petroleum Corporation, a
natural gas exploration and production company with operations in South Texas.
Calpine Natural Gas Company was merged into Calpine in April 2002, and Calpine
Natural Gas L.P. was subsequently established. In September 2004, Calpine and
Calpine Natural Gas L.P. sold their natural gas reserves in the New Mexico
San
Juan Basin and Colorado Piceance Basin and such properties have been reflected
as discontinued operations for all periods presented herein. Several members
of
the Calpine management team, who were responsible for operating Calpine’s oil
and natural gas business, joined the Company concurrently with the
Acquisition.
Our
Strengths
We
believe our historical success is, and future performance will be, directly
related to the following combination of strengths:
High
Quality, Diversified Asset Base.
We own a
geographically diversified asset base comprised of long-lived reserves along
with shorter-lived, higher return reserves. Approximately 96% of our reserves
are natural gas and almost all of our assets are located in the Sacramento
Basin
of California, South Texas, the Gulf of Mexico and the Rocky Mountains. We
believe this geographic and production profile diversity will enhance the
stability of our cash flows while providing us with a large number of
development and exploration opportunities, as well as support for additional
acquisitions.
Development
and Exploration Drilling Inventory.
We have
identified over 500 drillable, low to moderate risk opportunities providing
us
with multiple years of drilling inventory, and we expect to drill approximately
190 of these locations during 2007. Approximately 20% of these locations are
classified as proved undeveloped. We also have a large and diversified portfolio
of what we designate as development and exploration prospects. Our capital
expenditure budget is approximately $250 million for 2007. We will manage our
exploratory risks and expenditures by selectively reducing our capital exposure
in certain high risk projects by partnering with others in our
industry.
Operational
Control.
We
operate approximately 90% of our estimated proved reserves, which allows us
to
more effectively manage expenses and control the timing of capital allocation
of
our development and exploration activities.
Experienced
Management Team.
Our
executive management team has an average of over 30 years of experience in
the
oil and natural gas industry as well as strong technological
backgrounds.
Proven
Technical and Land Personnel with Access to Technological
Resources.
Our
technical staff of 28 includes geologists, geophysicists, landmen, engineers
and
technicians with an average of over 20 years of relevant technical experience.
Our staff has a proven record of analyzing complex structural and stratigraphic
plays using 3-D geophysical expertise, producing and optimizing low pressure
natural gas reservoirs, detecting low contrast, low permeability pay
opportunities, drilling, completing and fracing of deep tight natural gas
reservoirs operating in the Gulf of Mexico and managing horizontal drilling
and
coalbed methane operations. These core competencies helped us to achieve a
drilling success rate of 85% for the year ended December 31, 2006 and has
helped maximize recovery from our reservoirs. Our definition of drilling success
is a well that produces hydrocarbons at sufficient rates to allow us to recover,
at a minimum, our capital investment and operating costs.
Our
Strategy
Our
strategy is to increase stockholder value by profitably increasing our reserves,
production, cash flow and earnings using a balanced program of
(1) developing existing properties, (2) exploring undeveloped
properties, (3) completing strategic acquisitions (4) maintaining
financial flexibility (5) striving to be a low cost producer, and (6)
maintaining financial flexibility. We will seek to accomplish these goals while
working to protect shareholder interests by conserving natural resources,
monitoring emerging trends, minimizing liabilities through an aggressive
approach to governmental compliance, respecting the dignity of human life,
and
protecting the environment. The following are key elements of our
strategy:
Further
Development to Existing Properties.
We
intend to further develop the significant remaining upside potential of our
properties by working over existing wells, drilling in-fill locations, drilling
step-out wells to expand known field outlines, recomplete to logged behind
pipe
pays and lowering field line pressures through compression for additional
reserve recovery.
Exploration
Growth.
We
intend to focus on niche areas in which we have technological and operational
advantages. This growth will come from higher-risk, higher-impact opportunities
in the Gulf of Mexico, Texas and Louisiana State Waters, in deep horizons in
the
Sacramento Basin, and from lower-risk, longer-lived opportunities in the shallow
Sacramento Basin, the Lobo and Perdido Sand Trends in South Texas, Niobrara
chalk in the DJ Basin and coalbed methane in the San Juan Basin. While the
majority of our prospects will be internally generated, we will, from time
to
time, participate in third-party drilling opportunities.
Acquisition
Growth.
We
continually review opportunities to acquire producing properties, undeveloped
acreage and drilling prospects. We focus on opportunities where we believe
our
reservoir management and operational expertise will enhance the value and
performance of acquired properties. Acquisition targets will generally be in
and
around our major producing and activity areas. We will also use our minor
producing field ownerships as islands of control and knowledge to make strategic
acquisitions. Historically, our management team has demonstrated success in
oil
and gas acquisitions and has developed a significant oil and gas knowledge
base
in fields throughout the United States.
Maintain
Technological Expertise.
We
intend to maintain the technological expertise that helped us achieve a drilling
success rate of 85% for the year ended December 31, 2006, and helped us
maximize field recoveries. We will use advanced geological and geophysical
technologies, detailed petrophysical analyses, state-of-the-art reservoir
engineering and sophisticated completion and stimulation techniques to grow
our
reserves and production.
Endeavor
to be a Low Cost Producer.
We will
strive to minimize our operating costs by concentrating our assets within
geographic areas where we can capture operating efficiencies. This is
particularly true in the Sacramento Basin and South Texas where we are a
dominant producer in each region.
Maintain
Financial Flexibility.
We
intend to optimize unused borrowing capacity under our revolving line of credit
by periodically refinancing our bank debt in the capital markets when conditions
are favorable. As of December 31, 2006, we had $159.0 million available for
borrowing under our revolving line of credit. Additionally, we expect internally
generated cash flow to provide additional financial flexibility, allowing us
to
pursue our business strategy. We intend to actively manage our exposure to
commodity price risk in the marketing of our oil and natural gas production.
As
part of this strategy and in connection with our credit facilities, we entered
into natural gas fixed-price swaps and costless collar transactions for a
significant portion of our expected production through 2009. We may enter into
other agreements, including fixed price, forward price, physical purchase and
sales, futures, financial swaps, option and put option
contracts.
Calpine
Bankruptcy
On
December 20, 2005 Calpine and certain of its subsidiaries filed for protection
under federal bankruptcy laws in the United States Bankruptcy Court of the
Southern District of New York (the “Bankruptcy Court”). The filing raises
certain concerns regarding aspects of our relationship with Calpine which we
will continue to closely monitor as the Calpine bankruptcy proceeds. See Item
3.
Legal Proceedings for further information regarding the Calpine
bankruptcy.
Our
Operating Areas
We
own
producing and non-producing oil and natural gas properties in the Sacramento
Basin of California, the Lobo and Perdido Trends in South Texas, the State
Waters of Texas, the Gulf of Mexico, the Rocky Mountains and other properties
located in various geographical areas in the United States. In each area we
are
pursuing geological objectives and projects that are consistent with our
technical expertise in order to provide the highest potential economic returns.
For the year ended December 31, 2006, we have drilled 142 gross and 120 net
wells, of which 85% found commercial quantities of production. The following
is
a summary of our major operating areas in which we discuss their various
characteristics. With respect to acreage information in this report, we have
included acreage relating to properties for which legal title was not given
to
us by Calpine on the original date of Acquisition because consents to
transfer, which the parties believed at that time were required, had not been
obtained as of July 7, 2005. See Item 3. Legal Proceedings for further
information regarding the Calpine bankruptcy.
California-Sacramento
Basin
Rio
Vista Field and Surrounding Area.
The Rio
Vista Gas Unit and a significant portion of the deep rights below the Rio Vista
Gas Unit, together constitute the greater Rio Vista Field, is the largest
onshore natural gas field in California and one of the 15 largest natural gas
fields in the United States. The field has produced a cumulative 3.6 Tcfe of
natural gas reserves to date since its discovery in 1936. We currently produce
from or have behind-pipe reserves in over 16 different zones at depths ranging
from 2,500 feet to 9,300 feet in the field. The natural gas field trap is a
faulted, downthrown rollover anticline, elongated to the northwest. The current
productive area is approximately ten miles long and eight miles wide. A majority
of the reservoirs are depletion driven with long production histories. For
the
twelve months ended December 31, 2006, the average net daily production in
the Sacramento Basin was approximately 31 MMcfe from 142 producing wells. As
of
December 31, 2006, we owned approximately 77,000 net acres in the Rio Vista
Field and surrounding Sacramento Basin areas. We are one of the largest
producers and leaseholders in the basin. Our acreage in the basin holds
significant low-risk, low-cost upside potential in 117 currently shut-in or
idle
wells, and over 110 drillable locations, and numerous workover and
recompletion opportunities. Additional reserve potential exists in gathering
system optimization projects, numerous fracture stimulation opportunities in
lower permeability, low contrast pays, and deeper gas bearing
sands.
We
drilled 19 successful wells in and around the Rio Vista field in 2006. Six
wells were drilled in the southern portion of the field in extending pays in
three reservoirs: Upper Capay, Lower Capay and Martinez. A 12-square mile 3-D
program was shot over the Bradford Island area of the field. This area of the
field previously has never been covered by seismic data.
Sacramento
Valley Extension. We
believe our existing land position and financial strength will give us the
ability to continue expanding our Sacramento Basin operations. The Sacramento
Valley Extension Project is an extension of work and study done in the
redevelopment of the Rio Vista Field and non-operated drilling in nearby
reservoirs. Numerous plays are being evaluated, including Mokelumme gorge traps
and McCormick fault traps, deeper Winters traps, and shallow Emigh/Capay
truncation traps on the east side of the Sacramento Basin. Low contrast and
low
resistivity pays in the Emigh, Capay, Hamilton and Martinez formations are
being
pursued for under-exploited and unrecognized potential. We have approximately
581 square miles of 3-D seismic data and over 2,216 miles of 2-D seismic data
in
Rio Vista, the extension area, and the greater Sacramento Valley. The area
contains 16 prospective producing formations with historically high production
rates at shallow to moderate drill depths.
Other
Activities.
We are
actively pursuing additional lease acquisitions throughout the Sacramento Basin.
In 2006, we added approximately 16,400 acres to our leasehold inventory. We
have
one rig actively drilling in the field. We will be procuring a deep rig in
the
summer to drill three deep tests. In all, we plan to drill 30 wells in
2007. There are three completion rigs currently working on Rosetta wells in
the
Rio Vista area. Other than new well completions, we plan to conduct between
30
and 40 workover, recompletion or reactivation operations on field wells with
these rigs during 2007.
Lobo
Lobo
Trend.
Discovered in 1973, the Lobo Trend of South Texas is a complex, highly faulted
sand that has produced over 7 Tcf of natural gas. The Lobo section produces
from
tight sands with low permeabilities and high pressures at depths from 7,500
to
10,000 feet. We are a significant producer in the Lobo Trend, with over 65,000
net acres, 320 square miles of 3-D seismic data, approximately 239 active
operated wells and interests in approximately 120 non-operated wells. We
recently added a new acreage position in the heart of our acreage in the Lobo
Trend. For the year ended December 31, 2006, our average net daily
production from the Trend was 26.5 MMcfe. Our working interests range from
50%
to 100%. We have identified 90 potential drilling locations on our
acreage.
We
have
two drilling rigs under contract for the drilling program, and we plan to drill
30 wells in the Trend in 2007. We drilled 21 successful wells in
2006.
Perdido
Perdido
Sand Trend. We
own a
50% non-operating working interest in approximately 17,500 acres in the Perdido
Sand Trend. The Perdido Sands are in isolated fault blocks and are
stratigraphically trapped below the Upper Wilcox structures at approximately
8,000 to 9,500 feet. The Perdido Sands are comprised of tight natural gas sands
requiring significant fracture stimulation. Horizontal drilling has been very
successful in maximizing natural gas recovery. We plan to maintain our current
acreage and seismic position and to continue to improve horizontal drilling
techniques to lower cost and increase performance. For the twelve months ended
December 31, 2006, our average net daily production was 11.4 MMcfe from 28
producing wells. We participated in the drilling of 7 horizontal wells in 2006
with 6 successful. Two of the 7 wells were drilled in 2006 and completed in
January 2007. We plan to drill 7 additional wells in 2007.
Gulf
of Mexico
Federal
Waters.
The
Company owns working interests in 11 blocks ranging from 20% to 100%. We have
satisfied the regulatory requirement for receiving ministerial approval in
all
the offshore blocks in the Gulf of Mexico except for four blocks for which
we
have not received Mineral Management Service’s (“MMS”) ministerial
approvals. In 2006, we acquired ownership interests in another three blocks
in
the Gulf of Mexico. For the year ended December 31, 2006, our average net daily
production from these blocks was 8.3 MMcfe.
During
2006, through our participation in a joint venture, we acquired a 25%
non-operated working interest in two OCS blocks, Main Pass Block 118 and Main
Pass Block 117. Main Pass Block 118 well No. 1 was drilled, production
casing set, successfully tested and is awaiting platform installation. The
Block
117 well No. 1 was a dry hole. We acquired a 50% working interest in Main
Pass Block 29 and a 25% working interest in Grand Isle Block 72. These wells
will be placed on production in 2007. We plan to drill 2 additional wells
in the Gulf of Mexico in 2007.
We
have
entered into an Area of Mutual Interest (“AMI”) agreement in which we have the
right to participate in up to a 50% working interest in wells within 150
Outer
Continental Shelf (“OCS”) blocks on the Louisiana offshore shelf. We have
obtained MMS leases for another three OCS blocks. We intend to participate
in
the drilling of at least one to two new prospects each year in these blocks,
as
well as other blocks in which we may obtain leases.
State
Waters of Texas
Galveston
Bay. We
continue exploring in the Vicksburg and Frio Trends in Galveston Bay, Texas,
specifically pursuing sands that exhibit strong hydrocarbon indicators on 3-D
seismic.
In
2006
we participated in the drilling of 5 wells; one of which is on production,
two
waiting on production facilities and two dry holes. Over average net daily
production was 3.1 MMcfe for 2006. We plan to drill 4 additional wells in
2007.
Sabine
Lake.
We own a
50% operated working interest through a joint venture in Sabine Lake, within
Texas State Waters of Jefferson County. We are currently drilling a 13,000
foot
test well which is one of four expected to be drilled in 2007. We currently
hold
interest in approximately 2,100 gross acres and have recently acquired an
additional interest in approximately 4,800 acres in the same area.
Other
Onshore
Live
Oak County Prospect.
Through
the interpretation of 3-D seismic data, we have identified four structures
at
approximately 16,500 feet in the Sligo Reef Trend in Live Oak County, Texas.
Two
of these structures were previously drilled and produced by other operators.
One
structure has produced 33 Bcfe since 1983 from one well on the south end of
our
3-D data coverage, and a second structure on the north end of our data coverage
produced 13 Bcfe since 1987, also from one well. We currently have approximately
2,500 net acres under lease and have obtained a partner to join in the drilling
of the initial exploratory well to a depth of 17,000 feet. The Exploration
Agreement provides for the formation of an AMI covering approximately 22,000
acres for exploration and development purposes. The initial well should commence
operations prior to August 31, 2007.
Frio, Vicksburg,
Yegua and Wilcox Trends.
In
Colorado and Wharton Counties, we are pursuing amplitude plays between 3,500
and
7,000 feet in the Frio and Yegua Trends. In the Wilcox Trend, we are pursuing
normally pressured structural closures at 10,000 feet and over-pressured
closures from 14,000 to 17,500 feet. All of these projects are based on 3-D
seismic data. In 2006, we drilled 6 wells and participated
in 2 others, with a 50% success rate. We continue to look for
additional opportunities in these trends.
We
plan
to drill 18 additional wells in 2007 in the Other Onshore area.
Rocky
Mountains
We
are
active in the DJ and San Juan Basins in the Rocky Mountains.
DJ
Basin, Colorado.
As of
December 31, 2006, we had a majority working interest in approximately
95,000 net acres in the Niobrara Chalk play at 2,500 feet. In 2006 we drilled
46
locations, 43 of which were successful. As of December 31, 2006 we have
identified approximately 200 additional locations on our existing leases
with 70 wells planned for 2007. For the year ended December 31, 2006, our
average production from the area was approximately 1 MMcfe/d.
By
December 31, 2006, we had acquired 91.1 square miles of 3D seismic data, 61
square miles of which was acquired in 2006. We are using 3-D seismic data as
a
critical tool in identifying potential drilling opportunities. We drilled 33
successful wells out of 33 attempts in the Republican River 3-D area in 2006.
Pipeline and gathering system construction is underway in the Republican River.
Additional pipeline, gathering line and water collection pits were permitted
and
installed in the Kitzmiller area.
San
Juan Basin, New Mexico.
The San
Juan Basin is the second most prolific gas basin in North America, according
to
published articles, with 34 Tcf of production through the end of October 2004,
11.4 Tcf of which comes from the Fruitland Coal CBM (“Coal Bed Methane”). There
is Fruitland Coal production from depths of 1,600 feet surrounding our
leasehold. We are pursuing this coalbed methane play and had, as of
December 31, 2006, a 100% working interest position in approximately 7,500
acres. The well permitting process is ongoing. In 2006 we drilled 14 Fruitland
Coal CBM wells and 1 saltwater disposal well. We have identified 40 drillable
locations on our San Juan Basin leases with 18 wells planned for
2007.
Mid-Continent
Texas
Panhandle —Price Ranch Project. On
February 10, 2006, we acquired a farmout from BP on approximately 12,800
acres in Sherman County, Texas, to explore for oil and gas reserves in the
Marmaton Limestone and Morrow Sandstone. The acreage is held by production
by
shallower Chase Formation Hugoton gas production. The farmout includes access
to
a proprietary BP 22 square miles of 3-D seismic survey, which was reprocessed
for prospect development. We have acquired a 3.5-mile 2-D seismic line to
evaluate several well locations offsetting existing Marmaton production. Three
drillable prospects resulted from the seismic and geologic evaluations.
Subsequent to December 31, 2006, one of these prospects has been drilled, and
another is expected to commence drilling by the end of the first quarter of
2007.
Crude
Oil and Natural Gas Operations
Production
by Operating Area
The
following table presents certain information with respect to our production
data
for the period presented:
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For
the Year Ended December 31, 2006 (1)
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||||||||||
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Natural
Gas
(Bcf)
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Oil
(MMBbls)
|
Equivalents
(Bcfe)
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||||||||
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California
|
11.4
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-
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11.5
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|||||||
|
Lobo
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9.3
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-
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9.7
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|||||||
|
Perdido
|
4.0
|
-
|
4.2
|
|||||||
|
State
Waters
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1.1
|
-
|
1.1
|
|||||||
|
Gulf
of Mexico
|
1.5
|
0.3
|
3.0
|
|||||||
|
Other
Onshore
|
2.4
|
0.2
|
3.3
|
|||||||
|
Rocky
Mountains
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0.4
|
-
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0.4
|
|||||||
|
Mid-Continent
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0.2
|
-
|
0.2
|
|||||||
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30.3
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0.5
|
33.4
|
||||||||
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(1)
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Excludes
properties not conveyed as part of the Acquisition of the domestic
oil and
natural gas properties of Calpine, as described in the footnotes
for
proved reserves below.
|
Proved
Reserves
There
are
a number of uncertainties inherent in estimating quantities of proved reserves,
including many factors beyond our control, such as commodity pricing. Therefore,
the reserve information in this report represents only estimates. Reserve
engineering is a subjective process of estimating underground accumulations
of
oil and natural gas that cannot be measured in an exact manner. The accuracy
of
any reserve estimate is a function of the quality of available data and of
engineering and geological interpretation and judgment. As a result, estimates
of different engineers may vary. In addition, results of drilling, testing
and
production subsequent to the date of an estimate may justify revising the
original estimate. Accordingly, initial reserve estimates are often different
from the quantities of oil and natural gas that are ultimately recovered. The
meaningfulness of such estimates depends primarily on the accuracy of the
assumptions upon which they were based. Except to the extent that we acquire
additional properties containing proved reserves or conduct successful
exploration and development activities, or both, our proved reserves will
decline as reserves are produced.
As
of
December 31, 2006, we had 407.8 Bcfe of proved oil and natural gas
reserves, including 390.2 Bcf of natural gas and 2,930 MBbls of oil and
condensate. Using prices as of December 31, 2006, (adjusted for basis and
quality differentials) the estimated standardized measure of discounted future
net cash flows was $721.7 million. The following table sets forth by operating
area a summary of our estimated net proved reserve information as of
December 31, 2006:
|
Estimated
Proved Reserves at December 31, 2006 (1)(2)(3)
|
|||||||||||||
|
Developed
(Bcfe)
|
Undeveloped
(Bcfe)
|
Total
(Bcfe)
|
Percent
of Total Reserves
|
||||||||||
|
California
|
115.4
|
37.2
|
152.6
|
37
|
%
|
||||||||
|
Lobo
|
87.7
|
83.7
|
171.4
|
42
|
%
|
||||||||
|
Perdido
|
8.3
|
11.6
|
19.9
|
5
|
%
|
||||||||
|
State
Waters
|
2.2
|
-
|
2.2
|
1
|
%
|
||||||||
|
Gulf
of Mexico
|
13.8
|
1.8
|
15.6
|
4
|
%
|
||||||||
|
Other
Onshore
|
18.4
|
6.6
|
25.0
|
6
|
%
|
||||||||
|
Rockies
|
15.0
|
3.5
|
18.5
|
4
|
%
|
||||||||
|
Mid-Continent
|
2.1
|
0.5
|
2.6
|
1
|
%
|
||||||||
|
Total
|
262.9
|
144.9
|
407.8
|
100
|
%
|
||||||||
|
(1)
|
These
estimates are based upon a reserve report prepared by Netherland
Sewell & Associates, Inc. (hereafter “Netherland Sewell”) using
criteria in compliance with the Securities and Exchange Commission
(“SEC”)
guidelines and excludes 23.4 Bcfe of proved oil and gas reserves
with an
SEC PV-10 value of $53.0 million pretax representing the total allocated
value of wells and the associated leases described in footnote 2
below.
|
|
(2)
|
At
the July 2005 closing of the Acquisition, we withheld $68 million
for
properties (excluding that portion of the properties subject to the
preferential right) which Calpine agreed to transfer legal title
to us but
for which Calpine had not then secured consents to assign, which
the
parties believed at that time were required (“Non-Consent Properties”).
Subsequent analysis determined that a portion of these properties,
having
an allocated value withheld under the Purchase Agreement at closing
of $29
million, did not require such consent. Consents now have been received
for
the remaining properties as to which the allocated value under the
Purchase Agreement withheld at closing, was $39 million (“Cured
Non-Consent Properties”). We are prepared to pay Calpine the retained
portion of the original purchase price, upon our receipt from Calpine
of
record legal title on these properties, free of any encumbrance,
subject
to appropriate adjustment for the net revenues through the relevant
pre-petition period related to the Cured Non-Consent Properties,
and
Calpine’s performance of its obligations under the “further assurances”
provisions of the Purchase
Agreement.
|
|
(3)
|
Includes
properties subject to additional documentation or completion of
ministerial actions by federal or state agencies necessary to perfect
legal title issues discovered during routine post-closing analysis
after
the Acquisition of the domestic oil and natural gas business from
Calpine,
for which Calpine is contractually obligated to assist in
resolving.
|
2006 Capital Expenditures
The
following table summarizes information regarding development and exploration
capital expenditures for the year ended December 31, 2006 (Successor), six
months ended December 31, 2005 (Successor), the six months ended
June 30, 2005 (Predecessor) and the capital expenditures for the year ended
December 31, 2004 (Predecessor).
|
Successor
|
Predecessor
|
||||||||||||
|
Year
Ended
December
31, 2006
|
Six
Months Ended
December
31, 2005
|
Six
Months Ended
June
30, 2005
|
Year
Ended
December
31, 2004
|
||||||||||
|
(In
thousands)
|
|||||||||||||
|
Capital
Expenditures by Operating Area:
|
|||||||||||||
|
California
|
$
|
39,691
|
$
|
3,933
|
$
|
4,572
|
$
|
8,239
|
|||||
|
Lobo
|
51,911
|
6,775
|
2,020
|
8,670
|
|||||||||
|
Perdido
|
25,971
|
9,268
|
12,441
|
18,683
|
|||||||||
|
Texas
State Waters
|
13,028
|
3,023
|
3,417
|
-
|
|||||||||
|
Other
Onshore
|
10,207
|
10,831
|
2,300
|
8,207
|
|||||||||
|
Gulf
of Mexico
|
17,958
|
9,369
|
4,556
|
4,174
|
|||||||||
|
Rocky
Mountains
|
15,299
|
3,035
|
1,102
|
-
|
|||||||||
|
Mid-Continent
|
3,371
|
317
|
220
|
300
|
|||||||||
|
Leasehold
|
16,383
|
9,224
|
2,617
|
3,559
|
|||||||||
|
New
acquisitions
|
35,105
|
5,524
|
-
|
-
|
|||||||||
|
Delay
rentals
|
728
|
143
|
443
|
507
|
|||||||||
|
Geological
and geophysical/seismic
|
3,748
|
5,659
|
513
|
199
|
|||||||||
|
Total
capital expenditures (1)
|
$
|
233,400
|
$
|
67,101
|
$
|
34,201
|
$
|
52,538
|
|||||
|
(1)
|
Capital
expenditures for the year ended December 31, 2006 (Successor)
excludes capitalized overhead costs of $3.4 million, capitalized
interest of $2.1 million and corporate other capitalized costs of
$1.7
million. The six months ended December 31, 2005 (Successor) excludes
capitalized interest of $0.6 million, corporate other capitalized
costs of
$1.6 million and capitalized overhead costs of $1.7 million.
Corporate other capitalized costs consist of costs related to IT
software/hardware, office furniture and fixtures and license transfer
fees. The six-month period ended June 30, 2005 (Predecessor) excludes
$(0.7) million of capitalized interest and $1.7 million of overhead.
The
amount for 2004 (Predecessor) excludes $1.3 million of capitalized
interest, $3.1 million of overhead, $10.0 million of compressor station
and gathering system expense and $1.4 million for acquisition properties.
Our total capital expenditures in 2004 of $52.5 million, including
these
exclusions, corresponds to 2004 total capital costs of $69 million
as
defined under Statement of Financial Accounting Standards (“SFAS”)
No. 19, “Financial Accounting and Reporting by Oil and Gas Producing
Companies” in the Supplemental Oil and Gas Disclosure under Item 8 of
this report.
|
Productive
Wells and Acreage
The
following table sets forth our interest in undeveloped acreage, developed
acreage and productive wells in which we own a working interest as of
December 31, 2006. Gross represents the total number of acres or wells in
which we own a working interest. Net represents our proportionate working
interest resulting from our ownership in the gross acres or wells. Productive
wells are wells in which we have a working interest and that are capable of
producing oil or natural gas.
|
Undeveloped
Acres (1)
|
Developed
Acres (1)
|
Productive
Wells
|
|||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
||||||||||||||
|
California
|
45,364
|
35,247
|
47,184
|
41,695
|
142
|
118
|
|||||||||||||
|
Lobo
|
24,716
|
21,105
|
53,519
|
45,699
|
359
|
188
|
|||||||||||||
|
Perdido
|
4,128
|
2,073
|
13,898
|
6,940
|
28
|
14
|
|||||||||||||
|
Texas
State Waters
|
8,860
|
4,536
|
2,408
|
715
|
2
|
1
|
|||||||||||||
|
Other
Onshore
|
11,647
|
7,651
|
29,797
|
21,608
|
161
|
45
|
|||||||||||||
|
Gulf
of Mexico (2)
|
15,805
|
9,375
|
38,695
|
22,514
|
4
|
3
|
|||||||||||||
|
Rocky
Mountains
|
189,511
|
149,983
|
8,859
|
6,160
|
25
|
22
|
|||||||||||||
|
Mid-Continent
|
280
|
52
|
2,675
|
2,561
|
30
|
8
|
|||||||||||||
|
300,311
|
230,022
|
197,035
|
147,892
|
751
|
399
|
||||||||||||||
Capital
|
(1)
|
Includes
acreage relating to properties for which legal title was not transferred
to us on the original date of the Acquisition because consents to
transfer
which were believed at that time to be required and had not yet been
obtained is included in this table.
|
|
(2)
|
Offshore
productive wells are based on intervals rather than well
bores.
|
The
following table shows our interest in undeveloped acreage as of
December 31, 2006, which is subject to expiration in 2007, 2008, 2009, and
thereafter.
|
2007
|
2008
|
2009
|
Thereafter
|
|||||||||||||||||||
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
Gross
|
Net
|
|||||||||||||||
|
15,379
|
10,374
|
25,830
|
22,929
|
32,648
|
25,366
|
226,454
|
171,353
|
|||||||||||||||
Drilling
Activity
The
following table sets forth the number of gross exploratory and gross development
wells drilled in which we participated during the last three fiscal years.
The
number of wells drilled refers to the number of wells commenced at any time
during the respective fiscal year. Productive wells are either producing wells
or wells capable of commercial production. At December 31, 2006, we were in
the process of drilling six gross wells.
|
Gross
Wells
|
|||||||||||||||||||
|
Exploratory
|
Development
|
||||||||||||||||||
|
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
||||||||||||||
|
2006
|
68.0
|
15.0
|
83.0
|
51.0
|
8.0
|
59.0
|
|||||||||||||
|
2005
|
7.0
|
5.0
|
12.0
|
41.0
|
3.0
|
44.0
|
|||||||||||||
|
2004
|
8.0
|
2.0
|
10.0
|
40.0
|
2.0
|
42.0
|
|||||||||||||
The
following table sets forth, for each of the last three fiscal years, the number
of net exploratory and net development wells drilled by us based on our
proportionate working interest in such wells.
|
Net
Wells
|
|||||||||||||||||||
|
Exploratory
|
Development
|
||||||||||||||||||
|
Productive
|
Dry
|
Total
|
Productive
|
Dry
|
Total
|
||||||||||||||
|
2006
|
58.5
|
10.0
|
68.5
|
45.0
|
6.2
|
51.2
|
|||||||||||||
|
2005
|
3.4
|
3.4
|
6.8
|
23.5
|
3.0
|
26.5
|
|||||||||||||
|
2004
|
4.3
|
1.0
|
5.3
|
21.1
|
2.0
|
23.1
|
|||||||||||||
Marketing
and Customers
Pursuant
to our natural gas purchase and sales contract with Calpine and its
subsidiaries, we are obligated to sell all of the then-existing and future
production from our California leases in production as of May 1, 2005,
through December 2009, based on market prices. Calpine maintains a right of
first refusal for a term of 10 years after the primary term. As of
December 31, 2006, this production comprised approximately 40% of our
current overall daily equivalent production. Under the terms of our gas purchase
and sale contract and spot agreements with Calpine, cash payment for all natural
gas volumes that are contractually sold to Calpine on the previous day are
deposited into our collateral bank account. If the funds are not deposited
one
business day in arrears in accordance with our contract, we are not obligated
to
continue to sell our production to Calpine and these sales can then cease
immediately. We would then be in a position to market this natural gas
production to other parties. Calpine has 60 days to pay amounts owed to us,
at
which time we are obligated under the contract to resume natural gas sales
to
Calpine. We believe that Calpine’s bankruptcy will have no significant effect on
our ability to sell our natural gas at market prices. Additionally, while we
may
market our natural gas production, which is not subject to the above mentioned
natural gas contract, to parties other than Calpine, an affiliate of Calpine
is
under contract through June 30, 2007, to provide us administrative services
in
connection with such marketing efforts.
All
of
our other production is sold to various purchasers, including Calpine, on a
competitive basis.
Major
Customers
For
the
year ended December 31, 2006, the Company had two major customers, which
accounted for approximately 60% of the Company’s consolidated annual revenue.
Calpine Energy Services (“CES”) was one of the major customers and accounted for
approximately 45% of the Company’s consolidated annual revenue. Total Gas and
Power was the other major customer.
Competition
The
oil
and natural gas industry is highly competitive, and we compete with a
substantial number of other companies that have greater resources. Many of
these
companies explore for, produce and market oil and natural gas, carry on refining
operations and market the resultant products on a worldwide basis. The primary
areas in which we encounter substantial competition are in locating and
acquiring desirable leasehold acreage for our drilling and development
operations, locating and acquiring attractive producing oil and natural gas
properties, and obtaining purchasers and transporters of the oil and natural
gas
we produce. There is also competition between producers of oil and natural
gas
and other industries producing alternative energy and fuel. Furthermore,
competitive conditions may be substantially affected by various forms of energy
legislation and/or regulation considered from time to time by the federal,
state
and local government; however, it is not possible to predict the nature of
any
such legislation or regulation that may ultimately be adopted or its effects
upon our future operations. Such laws and regulations may, however,
substantially increase the costs of exploring for, developing or producing
natural gas and oil and may prevent or delay the commencement or continuation
of
a given operation. The effect of these risks cannot be accurately
predicted.
Seasonal
Nature of Business
Generally,
but not always, the demand for natural gas decreases during the summer months
and increases during the winter months. Seasonal anomalies such as mild winters
or abnormally hot summers sometimes lessen this fluctuation. In addition,
certain natural gas users utilize natural gas storage facilities and purchase
some of their anticipated winter requirements during the summer. This can also
lessen seasonal demand fluctuations. Seasonal weather conditions and lease
stipulations can limit our drilling and producing activities and other oil
and
natural gas operations in certain areas of the Rocky Mountain region. These
seasonal anomalies can increase competition for equipment, supplies and
personnel during the spring and summer months, which could lead to shortages
and
increase costs or delay our operations.
Regulation
The
oil
and natural gas industry in the United States is subject to extensive regulation
by federal, state and local authorities. We hold onshore and offshore federal
leases involving the United States Department of Interior (the Bureau of Land
Management, the Bureau of Indian Affairs and the Minerals Management Service).
At the federal level, various federal rules, regulations and procedures apply,
including those issued by the United States Department of Interior as noted
above, and the United States Department of Transportation (U.S. Coast Guard
and
Office of Pipeline Safety). At the state and local level, various agencies
and
commissions regulate drilling, production and midstream activities. These
federal, state and local authorities have various permitting, licensing and
bonding requirements. Varied remedies are available for enforcement of these
federal, state and local rules, regulations and procedures, including fines,
penalties, revocation of permits and licenses, actions affecting the value
of
leases, wells or other assets, and suspension of production. As a result, there
can be no assurance that we will not incur liability for fines and penalties
or
otherwise subject us to the various remedies as are available to these federal,
state and local authorities. However, we believe that we are currently in
material compliance with these federal, state and local rules, regulations
and
procedures.
Transportation
and Sale of Natural Gas. The
Federal Energy Regulatory Commission (“FERC”) regulates interstate natural gas
pipeline transportation rates and service conditions. Although the FERC does
not
regulate natural gas producers such as us, the agency’s actions are intended to
foster increased competition within all phases of the natural gas industry.
To
date, the FERC’s pro-competition policies have not materially affected our
business or operations. It is unclear what impact, if any, future rules or
increased competition within the natural gas industry will have on our natural
gas sales efforts.
The
FERC,
the United States Congress or state regulatory agencies may consider additional
proposals or proceedings that might affect the natural gas industry. We cannot
predict when or if these proposals will become effective or any effect they
may
have on our operations. We do not believe, however, that any of these proposals
will affect us any differently than other natural gas producers with which
we
compete.
Regulation
of Production.
Oil and
natural gas production is regulated under a wide range of federal, state and
municipal (or other local) statutes, rules, orders and regulations. Federal,
state and municipal statutes and regulations require permits for drilling
operations, drilling bonds and reports concerning operations. The states in
which we own and operate properties have regulations governing conservation
matters, including provisions for the unitization or pooling of oil and natural
gas properties, the establishment of maximum rates of production from oil and
natural gas wells and the regulation of the spacing and plugging and abandonment
of wells. Many states also restrict production to the market demand for oil
and
gas, and several states have indicated interest in revising applicable
regulations. These regulations limit the amount of oil and gas we can produce
from our wells and limit the number of wells or the locations at which we can
drill. Also, each state generally imposes an ad valorem, production or severance
tax with respect to production and sale of oil, natural gas and natural gas
liquids within its jurisdiction.
U.S.
Minerals Management Services of the Department of the
Interior. The MMS
has
broad authority to regulate our oil and natural gas operations on offshore
leases in federal waters. It must approve and grant permits in connection with
our drilling and development plans. Additionally, the MMS has promulgated
regulations requiring offshore production facilities to meet stringent
engineering and construction specifications restricting the flaring or venting
of natural gas, governing the plugging and abandonment of wells and controlling
the removal of production facilities. Under certain circumstances, the MMS
may
suspend or terminate any of our operations on federal leases, and has proposed
regulations that would permit it to expel unsafe operators from offshore
operations. Delays in the approval of plans and issuance of permits by the
MMS
because of staffing, economic, environmental or other reasons could adversely
affect our operations. The MMS has also established rules governing the
calculation of royalties and the valuation of oil and natural gas produced
from
federal onshore and offshore leases and regulations regarding deductible costs.
Environmental
Regulations. Processes
involved in the drilling, construction, extraction and transportation of oil
and
natural gas in the exploration and production industry are subject to extensive
operating rules and regulations that have been promulgated by federal, state
and
local authorities with the intent of conserving natural resources, preservation
of the environment and protection of human health. Environmental regulations
affecting us prohibit or control the emitting or discharge of regulated
pollutants into the atmosphere, underground sources of drinking water, ground
water supplies, surface waters of the United States, or to unprotected surface
soils on or in the vicinity of our operations. The environmental statutes
provide for sensitive habitat, endangered species, wetlands loss and waste
management practices. The standards in many cases require a lengthy and complex
process of obtaining licenses, permits and approvals from federal, state and
local agencies. Inherent in the environmental legal system affecting our
business are the following primary compliance obligations which often require
costly precautionary measures or lend us to serious enforcement
consequences:
|
·
|
Notification
requirements
|
|
·
|
Point
of discharge or “Waste End”
controls
|
|
·
|
Process
oriented controls and pollution
prevention
|
|
·
|
Regulation
of activities to protect resources, species or ecological
amenities
|
|
·
|
Safe
transportation requirements
|
|
·
|
Response
and remediation requirements
|
|
·
|
Compensation
requirements.
|
The
environmental regulations provide for criminal prosecution of responsible
corporate officials under certain circumstances. In addition, the environmental
regulations also provide for civil enforcement actions in certain
circumstances.
The
environmental laws with their implementing regulations with the most significant
impact on the oil and natural gas exploration and production industry include
the following:
|
·
|
Clean
Air Act (“CAA”)
|
|
·
|
Clean
Water Act (“CWA”)
|
|
·
|
Comprehensive
Environmental Response, Compensation & Liability Act
(“CERCLA”)
|
|
·
|
National
Environmental Policy Act (“NEPA”)
|
|
·
|
Oil
Pollution Act of 1990 (“OPA’90”)
|
|
·
|
Resource
Conservation & Recovery Act
(“RCRA”)
|
|
·
|
Safe
Drinking Water Act
|
|
·
|
Superfund
Amendments & Reauthorization Act
(“SARA”)
|
Environmental
laws and regulations are subject to change, and we are unable to predict the
ongoing cost of complying with them or their future impact on our operations.
A
violation of environmental laws and regulations and any related permits may
result in administrative, civil or criminal penalties, injunctions and delays.
Discharge of hydrocarbons or hazardous substances into the environment to the
extent the event is not insured, may result in substantial expense, including
both the cost to comply with the applicable laws and regulations and claims
made
by neighboring landowners and other third parties for personal injury and
property damage.
We
believe that we are currently in substantial compliance with the requirements
of
these statutes and related state and local laws and regulations, and that we
hold all necessary and up-to-date permits, registrations and other
authorizations to the extent they are required by our operations under such
laws.
Occupational
Safety & Health Act
(“OSHA”). The Williams-Steiger Occupational Safety and Health Act of 1970
requires, in part, that every employer covered under OSHA furnish its employees
a place of employment which is free from recognized hazards that are causing
or
are likely to cause death or serious physical harm to its employees. OSHA also
requires that employers comply with occupational safety and health standards
promulgated under OSHA, and that employees comply with standards, rules,
regulations and orders issued under the Act which are applicable to their own
actions and conduct. OSHA authorizes the Department of Labor to conduct
inspections, and to issue citations and proposed penalties for alleged
violations. OSHA, under section 20(b), also authorizes the Secretary of Health,
Education, and Welfare to conduct inspections and to question employers and
employees in connection with research and other related activities. OSHA
contains provisions for adjudication of violations, periods prescribed for
the
abatement of violations, and proposed penalties by the Occupational Safety
and
Health Review Commission, if contested by an employer or by an employee or
authorized representative of employees, and for judicial review.
Insurance
Matters
As
is
common in the oil and natural gas industry, we do not insure fully against
all
risks associated with our business either because such insurance is not
available or because premium costs are considered prohibitive. A loss not fully
covered by insurance could have a materially adverse effect on our financial
position, results of operations or cash flows. In analyzing our operations
and
insurance needs, and in recognition that we have a large number of individual
well locations with varied geographical distribution, we compared premium costs
to the likelihood of material loss of production. Based on this analysis, we
have elected, at this time, not to carry loss of production or business
interruption insurance for our operations.
Employees
As
of
March 5, 2007, we have 135 full time employees. We also contract for the
services of independent consultants involved in land, regulatory accounting,
financial and other disciplines as needed. None of our employees are represented
by labor unions or covered by any collective bargaining agreement. We believe
that our relations with our employees are satisfactory.
Access
to Company Reports
For
further information pertaining to us, you may inspect without charge at the
public reference facilities of the SEC at 100 F Street, NE, Room 1580,
Washington, D.C. 20549 any of our filings with the SEC. Copies of all or any
portion of the documents may be obtained by calling the SEC at 1-800-SEC-0330.
In addition, the SEC maintains a web site that contains reports, proxy and
information statements and other information that is filed electronically with
the SEC. The web site can be accessed at www.sec.gov.
Corporate
Governance Matters
Our
website is http://www.rosettaresources.com.
All
corporate filings with the SEC can be found on our website, as well as other
information related to our business. Under the Corporate Governance tab you
can
find copies of our Code of Business Conduct and Ethics, our Nominating and
Corporate Governance Committee Charter, our Audit Committee Charter, and our
Compensation Committee Charter.
Calpine’s
bankruptcy filing may adversely affect us in several
respects.
Calpine,
its creditors or interest holders may challenge the fairness of some or all
of
the Acquisition.
Five
and
one-half months after the Acquisition, Calpine and certain of its subsidiaries
(the “Debtors”) filed for protection under the federal bankruptcy laws in the
Bankruptcy Court on December 20, 2005 (the “Petition Date”). Calpine or its
Bankruptcy estate 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 alleged initial
transferee or the immediate or mediate transferee from the initial transferee)
should be voided or set aside as a fraudulent transfer or, alternatively,
entitles Calpine’s estate monetary relief to the extent Rosetta is found not to
have paid reasonably equivalent value. To prevail in such a legal action,
Calpine, its creditors or interest holders would be required to prove that
Calpine either:
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Transferred
its domestic oil and natural gas business to us with the intent of
hindering, delaying or defrauding its current or future creditors;
or
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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.
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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 and procedure of the Acquisition. Nonetheless, if after a
trial
on the merits, the Bankruptcy 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 Bankruptcy Court as of July 7,
2005, exceeded the purchase price determined and paid in July 2005. If the
Bankruptcy Court should so rule, a setting aside of the Acquisition would be
materially detrimental to us in that substantially all our properties conveyed
at the time of the Acquisition 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
Bankruptcy 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. See Item 3. Legal Proceedings for further information regarding the Calpine
bankruptcy.
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 legal title
to
certain domestic oil and natural gas properties, subject to obtaining various
third party consents or waivers of preferential purchase rights, which the
parties believe at the time were required, in order to effect transfer of legal
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 legal title for
these remaining properties, except those subject to properly executed
preferential rights to purchase. The SEC PV-10 value of these properties at
December 31, 2005 was approximately $72.4 million pretax. Based on our
internal calculations, we estimate the SEC PV-10 value of these properties
at
current market prices at December 31, 2006 to be approximately $53.0 million
pretax. 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
legal title, free of any encumbrances, 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 and
Calpine’s performance of its obligations under the “further assurances”
provisions of the Purchase Agreement.
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 Section 365 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 Bankruptcy 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 the Bankruptcy Court were to later conclude that the oil
and
natural gas leases are “unexpired leases of non-residential real property,” and
that we had no interest in them, we may be required to take further action
or
pay further consideration to complete the assignments of these interests or
Calpine could retain the leases. In light of Calpine’s obligations under the
Purchase Agreement and rights afforded purchasers of real property, we would
oppose any such request or effort. Any failure by Calpine to complete the
corrective action necessary to remove title deficiencies with respect to certain
of these properties, including decision of the Bankruptcy Court not to require
Calpine to deliver corrective documentation or to require us to pay additional
consideration, could result in a material adverse effect on our results of
operations or financial condition if we are not able to receive any offsetting
refund of the portion of the purchase price attributable to those properties
or
if the amount of additional consideration we are required to pay is
material.
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.
Oil
and natural gas prices are volatile, and a decline in oil and natural gas prices
would significantly affect our financial results and impede our
growth.
Our
revenue, profitability and cash flow depend substantially upon the prices and
demand for oil and natural gas. The markets for these commodities are volatile
and even relatively modest drops in prices can significantly affect our
financial results and impede our growth. Prices for oil and natural gas
fluctuate widely in response to relatively minor changes in the supply and
demand for oil and natural gas, market uncertainty and a variety of additional
factors beyond our control, such as:
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Domestic
and foreign supply of oil and gas;
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Price
and quantity of foreign imports;
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Actions
of the Organization of Petroleum Exporting Countries and state-controlled
oil companies relating to oil price and production
controls;
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Domestic
and foreign governmental
regulations;
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Political
conditions in or affecting other oil producing and natural gas producing
countries, including the current conflicts in the Middle East and
conditions in South America and
Russia;
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Weather
conditions and natural disasters;
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Technological
advances affecting oil and natural gas
consumption;
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Overall
U.S. and global economic conditions;
and
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Price
and availability of alternative
fuels.
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Further,
oil and natural gas prices do not necessarily fluctuate in direct relationship
to each other. Because the majority of our estimated proved reserves are natural
gas reserves, our financial results are more sensitive to movements in natural
gas prices. Lower oil and natural gas prices may not only decrease our revenues
on a per unit basis but also may reduce the amount of oil and natural gas that
we can produce economically. Thus a significant reduction in commodity prices
may result in our having to make substantial downward adjustments to our
estimated proved reserves and could have a material adverse effect on our
financial condition, results of operations and cash flows.
Development
and exploration drilling activities do not ensure reserve replacement and thus
our ability to produce revenue.
Development
and exploration drilling and strategic acquisitions are the main methods of
replacing reserves. However, development and exploration drilling operations
may
not result in any increases in reserves for various reasons. Development and
exploration drilling operations may be curtailed, delayed or cancelled as a
result of:
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Lack
of acceptable prospective acreage;
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Inadequate
capital resources;
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Weather
conditions and natural disasters;
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Title
problems;
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Compliance
with governmental regulations;
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Mechanical
difficulties; and
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Availability
of equipment.
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Counterparty
credit default could have an adverse effect on us.
Our
revenues are generated under contracts with various counterparties. Results
of
operations would be adversely affected as a result of non-performance by any
of
these counterparties of their contractual obligations under the various
contracts. A counterparty’s default or non-performance could be caused by
factors beyond our control such as a counterparty experiencing credit default.
A
default could occur as a result of circumstances relating directly to the
counterparty, or due to circumstances caused by other market participants having
a direct or indirect relationship with the counterparty. Defaults by
counterparties may occur from time to time, and this could negatively impact
our
results of operations, financial position and cash flows. Calpine’s recent
bankruptcy could result in the failure of Calpine to continue purchasing natural
gas from us under our natural gas purchase and sale agreements with Calpine
discussed below.
We
sell a significant amount of our production to one
customer.
In
connection with the Acquisition, we entered into a natural gas purchase and
sale
contract with Calpine that obligates us to sell all of the then-existing and
future production from our California leases in production as of May 1,
2005 through December 31, 2009 based on market prices. Calpine maintains a
right
of first refusal for a term of 10 years after the primary term. As of
December 31, 2006, this production comprised approximately 40% of our
current overall production based on an equivalent basis. Calpine’s recent
bankruptcy could result in failure of Calpine to continue purchasing natural
gas
from us. Additionally, under separate monthly spot agreements, we may sell
our
natural gas production, not subject to the term contract to Calpine, which
could
increase our credit exposure to Calpine. Under the terms of our natural gas
purchase and sale contract and spot agreements with Calpine, all natural gas
volumes that are contractually sold to Calpine are collateralized by Calpine
making margin payments one business day in arrears to our collateral account
equal to the previous day’s natural gas sales. In the event of a default by
Calpine, we could be exposed to the loss of up to four days of natural gas
sales
revenue under the contract, which at prices and volumes in effect as of
December 31, 2006 would be approximately $2.5 million.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline.
Our
future oil and natural gas production depends on our success in finding or
acquiring additional reserves. If we fail to replace reserves through drilling
or acquisitions, our level of production and cash flows will be affected
adversely. In general, production from oil and natural gas properties declines
as reserves are depleted, with the rate of decline depending on reservoir
characteristics. Our total proved reserves decline as reserves are produced.
Our
ability to make the necessary capital investment to maintain or expand our
asset
base of oil and natural gas reserves would be impaired to the extent cash flow
from operations is reduced and external sources of capital become limited or
unavailable. We may not be successful in exploring for, developing or acquiring
additional reserves.
We
will require additional capital to fund our future activities. If we fail to
obtain additional capital, we may not be able to implement fully our business
plan, which could lead to a decline in reserves.
Future
projects and acquisitions may depend on our ability to obtain financing beyond
our cash flow from operations. We will finance our business plan and operations
primarily with internally generated cash flow, bank borrowings, entering into
exploratory arrangements with other parties and publicly
or
privately raised equity. In the future, we will require substantial capital
to
fund our business plan and operations. Sufficient capital may not be available
on acceptable terms or at all. If we cannot obtain additional capital resources,
we may curtail our drilling, development and other activities or be forced
to
sell some of our assets on unfavorable terms.
The
terms of our credit facilities contain a number of restrictive and financial
covenants that limit our ability to pay dividends. If we are unable to comply
with these covenants, our lenders could accelerate the repayment of our
indebtedness.
The
terms
of our credit facilities subject us to a number of covenants that impose
restrictions on us, including our ability to incur indebtedness and liens,
make
loans and investments, make capital expenditures, sell assets, engage in
mergers, consolidations and acquisitions, enter into transactions with
affiliates, enter into sale and leaseback transactions, change our lines of
business and pay dividends on our common stock. We will also be required by
the
terms of our credit facilities to comply with financial covenant ratios. A
more
detailed description of our credit facilities is included in “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations—Liquidity and Capital Resources” and the footnotes to the
Consolidated/Combined Financial Statements.
A
breach
of any of the covenants imposed on us by the terms of our indebtedness,
including the financial covenants under our credit facilities, could result
in a
default under such indebtedness. In the event of a default, the lenders for
our
revolving credit facility could terminate their commitments to us, and they
and
the lenders of our second lien term loan could accelerate the repayment of
all
of our indebtedness. In such case, we may not have sufficient funds to pay
the
total amount of accelerated obligations, and our lenders under the credit
facilities could proceed against the collateral securing the facilities. Any
acceleration in the repayment of our indebtedness or related foreclosure could
adversely affect our business.
Properties
we acquire may not produce as expected, and we may be unable to determine
reserve potential, identify liabilities associated with the properties or obtain
protection from sellers against such liabilities.
We
continually review opportunities to acquire producing properties, undeveloped
acreage and drilling prospects; however, such reviews are not capable of
identifying all potential conditions. Generally, it is not feasible to review
in
depth every individual property involved in each acquisition. Ordinarily, we
will focus our review efforts on higher value properties or properties with
known adverse conditions and will sample the remainder.
However,
even a detailed review of records and properties may not necessarily reveal
existing or potential problems or permit a buyer to become sufficiently familiar
with the properties to assess fully their condition, any deficiencies, and
development potential. Inspections may not always be performed on every well,
and environmental problems, such as ground water contamination are not
necessarily observable even when an inspection is undertaken.
Our
exploration and development activities may not be commercially
successful.
Exploration
activities involve numerous risks, including the risk that no commercially
productive oil or natural gas reservoirs will be discovered. In addition, the
future cost and timing of drilling, completing and producing wells is often
uncertain. Furthermore, drilling operations may be curtailed, delayed or
canceled as a result of a variety of factors, including:
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Unexpected
drilling conditions; pressure or irregularities in formations; equipment
failures or accidents;
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Adverse
weather conditions, including hurricanes, which are common in the
Gulf of
Mexico during certain times of the year; compliance with governmental
regulations; unavailability or high cost of drilling rigs, equipment
or
labor;
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Reductions
in oil and natural gas prices; and
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Limitations
in the market for oil and natural
gas.
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Our
decisions to purchase, explore, develop and exploit prospects or properties
depend in part on data obtained through geophysical and geological analyses,
production data and engineering studies, the results of which are often
uncertain. Even when used and properly interpreted, 3-D seismic data and
visualization techniques only assist geoscientists in identifying subsurface
structures and hydrocarbon indicators. They do not allow the interpreter to
know
conclusively if hydrocarbons are present or producible economically. In
addition, the use of 3-D seismic and other advanced technologies requires
greater pre-drilling expenditures than traditional drilling strategies. Because
of these factors, we could incur losses as a result of exploratory drilling
expenditures. Poor results from exploration activities could have a material
adverse effect on our future cash flows, results of operations and financial
position.
Numerous
uncertainties are inherent in our estimates of oil and natural gas reserves
and
our estimated reserve quantities and present value calculations may not be
accurate. Any material inaccuracies in these reserve estimates or underlying
assumptions will affect materially the estimated quantities and present value
of
our reserves.
Estimates
of proved oil and natural gas reserves and the future net cash flows
attributable to those reserves are prepared by independent petroleum engineers
and geologists. There are numerous uncertainties inherent in estimating
quantities of proved oil and natural gas reserves and cash flows attributable
to
such reserves, including factors beyond our control and that of our engineers.
Reserve engineering is a subjective process of estimating underground
accumulations of oil and natural gas that cannot be measured in an exact manner.
The accuracy of an estimate of quantities of reserves, or of cash flows
attributable to such reserves, is a function of the available data, assumptions
regarding future oil and natural gas prices, expenditures for future development
and exploration activities, engineering and geological interpretation and
judgment. Additionally, reserves and future cash flows may be subject to
material downward or upward revisions, based upon production history,
development and exploration activities and prices of oil and natural gas. Actual
future production, revenue, taxes, development expenditures, operating expenses,
underlying information, quantities of recoverable reserves and the value of
cash
flows from such reserves may vary significantly from the assumptions and
underlying information set forth herein. In addition, different reserve
engineers may make different estimates of reserves and cash flows based on
the
same available data. The present value of future net revenues from our proved
reserves referred to in this Report is not necessarily the actual current market
value of our estimated oil and natural gas reserves. In accordance with SEC
requirements, we base the estimated discounted future net cash flows from our
proved reserves on fixed prices and costs as of the date of the estimate. Actual
future prices and costs fluctuate over time and may differ materially from
those
used in the present value estimate. In addition, discounted future net cash
flows are estimated assuming royalties to the MMS, royalty owners and other
state and federal regulatory agencies with respect to our affected properties,
and will be paid or suspended during the life of the properties based upon
oil
and natural gas prices as of the date of the estimate. Since actual future
prices fluctuate over time, royalties may be required to be paid for various
portions of the life of the properties and suspended for other portions of
the
life of the properties.
The
timing of both the production and expenses from the development and production
of oil and natural gas properties will affect both the timing of actual future
net cash flows from our proved reserves and their present value. In addition,
the 10% discount factor that we use to calculate the net present value of future
net cash flows for reporting purposes in accordance with the SEC’s rules may not
necessarily be the most appropriate discount factor. The effective interest
rate
at various times and the risks associated with our business or the oil and
natural gas industry, in general, will affect the appropriateness of the 10%
discount factor in arriving at an accurate net present value of future net
cash
flows.
We
are subject to the full cost ceiling limitation which may result in a write-down
of our estimated net reserves.
Under
the
full cost method, we are subject to quarterly calculations of a “ceiling” or
limitation on the amount of our oil and gas properties that can be capitalized
on our balance sheet. If the net capitalized costs of our oil and gas properties
exceed the cost center ceiling, we are subject to a ceiling test write-down
of
our estimated net reserves to the extent of such excess. If required, it would
reduce earnings and impact stockholders’ equity in the period of occurrence and
result in lower amortization expense in future periods. The discounted present
value of our proved reserves is a major component of the ceiling calculation
and
represents the component that requires the most subjective judgments. However,
the associated hedge adjusted market prices of oil and gas reserves that are
included in the discounted present value of the reserves do not require
judgment. The ceiling calculation dictates that prices and costs in effect
as of
the last day of the quarter are held constant. However, we may not be subject
to
a write-down if prices increase subsequent to the end of a quarter in which
a
write-down might otherwise be required. The risk that we will be required to
write down the carrying value of oil and natural gas properties increases when
natural gas and crude oil prices are depressed or volatile. In addition,
write-down of proved oil and natural gas properties may occur if we experience
substantial downward adjustments to our estimated proved reserves or if
purchasers cancel long-term contracts for our natural gas production. As expense
recorded in one period may not be reversed in a subsequent period event though
higher natural gas and crude oil prices may have increased the ceiling
applicable in the subsequent period.
We
are subject to complex government regulation that could adversely affect our
operations.
Our
activities are subject to complex and stringent environmental and other
governmental laws and regulations. The exploration and production of oil and
natural gas requires numerous permits, approvals and certificates from
appropriate federal, state and local governmental agencies, including state
and
local agencies in California, whose regulations typically are more stringent
than in other states or localities, as well as compliance with environmental
protection legislation and other regulations. We remain subject to a varied
and
complex body of laws and regulations that both public officials and private
individuals may seek to enforce. Existing laws and regulations are routinely
revised or reinterpreted, and together with new laws and regulations may impact
us and have a negative effect on our business and results of operations. We
may
be unable to obtain all necessary licenses, permits, approvals and certificates
for proposed projects. Intricate and changing environmental and other regulatory
requirements may necessitate substantial expenditures to obtain and maintain
permits. If a project is unable to function as planned due to changing
requirements or local opposition, it may create expensive delays, extended
periods of non-operation or significant loss of value in a project.
Our
business is subject to federal, state and local laws and regulations as
interpreted by governmental agencies and other bodies, including those in
California, vested with authority over the exploration, development, production
and transportation of oil and natural gas, including environmental and safety
matters. Existing laws and regulations are routinely changed which could
increase costs of compliance and costs of operating drilling equipment, or
otherwise significantly limit drilling activity.
Under
certain circumstances, the MMS may require that our operations on federal leases
be suspended or terminated. These circumstances include our failure to pay
royalties or our failure to comply with safety and environmental regulations.
The requirements imposed by these laws and regulations are frequently changed
and subject to new interpretations, and if such were to occur, could negatively
impact our results of operations and cash flows.
Our
business requires technical expertise, specialized knowledge and training and
a
high degree of management experience.
Our
success is largely dependent on the skills, experience and efforts of our
employees. The loss of the services of one or more members of our senior
management or of numerous employees with critical skills could have a negative
effect on our business, financial conditions and results of operations and
future growth.
Our
results are subject to commodity price fluctuations related to seasonal and
market conditions and reservoir and production risks.
Our
quarterly operating results have fluctuated in the past and could be negatively
impacted in the future as a result of a number of factors,
including:
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Seasonal
variations in oil and natural gas
prices;
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Variations
in levels of production; and
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The
completion of exploration and production
projects.
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The
ultimate outcome of the legal proceedings relating to our activities cannot
be
predicted. Any adverse determination could have a material adverse effect on
our
financial condition, results of operations or cash
flows.
Operation
of our properties has generated various litigation matters arising out of the
normal course of business. In connection with the transfer and assumption
agreement with Calpine, we generally assumed liabilities arising from our
activities from and after the Acquisition, including defense of future
litigation and claims involving Calpine’s domestic oil and natural gas reserve
properties conveyed in the Acquisition, other than certain litigation that
Calpine and its subsidiaries retained liability or agreed to indemnify the
Company by agreement. Calpine’s bankruptcy may affect its obligations for the
retained liabilities and claims. The ultimate outcome of claims and litigation
relating to our activities cannot presently be determined, nor can the liability
that may potentially result from a negative outcome be reasonably estimated
at
this time for every case. The liability we 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 and, as a result, these
matters may potentially be material to our financial condition, results of
operations or cash flows.
Market
conditions or transportation impediments may hinder our access to oil and
natural gas markets or delay our production.
Market
conditions, the unavailability of satisfactory oil and natural gas processing
and transportation or the remote location of certain of our drilling operations
may hinder our access to oil and natural gas markets or delay our production.
The availability of a ready market for our oil and natural gas production
depends on a number of factors, including the demand for and supply of oil
and
natural gas and the proximity of reserves to pipelines or trucking and terminal
facilities. In the Gulf of Mexico operations, the availability of a ready market
depends on the proximity of and our ability to tie into existing production
platforms owned or operated by others and the ability to negotiate commercially
satisfactory arrangements with the owners or operators. We may be required
to
shut in natural gas wells or delay initial production for lack of a market
or
because of inadequacy or unavailability of natural gas pipelines or gathering
system capacity. When that occurs, we are unable to realize revenue from those
wells until the production can be tied to a gathering system. This can result
in
considerable delays from the initial discovery of a reservoir to the actual
production of the oil and natural gas and realization of revenues.
Competition
in the oil and natural gas industry is intense, and many of our competitors
have
resources that are greater than ours.
We
operate in a highly competitive environment for acquiring prospects and
productive properties, marketing oil and natural gas and securing equipment
and
trained personnel. Many of our competitors, major and large independent oil
and
natural gas companies, possess and employ financial, technical and personnel
resources substantially greater than our resources. Those companies may be
able
to develop and acquire more prospects and productive properties than our
financial or personnel resources permit. Our ability to acquire additional
prospects and discover reserves in the future will depend on our ability to
evaluate and select suitable properties and consummate transactions in a highly
competitive environment. Also, there is substantial competition for capital
available for investment in the oil and natural gas industry. Larger competitors
may be better able to withstand sustained periods of unsuccessful drilling
and
absorb the burden of changes in laws and regulations more easily than we can,
which would adversely affect our competitive position. We may not be able to
compete successfully in the future in acquiring prospective reserves, developing
reserves, marketing hydrocarbons, attracting and retaining quality personnel
and
raising additional capital.
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:
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Well
blowouts;
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Cratering;
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Explosions;
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Uncontrollable
flows of oil, natural gas or well
fluids;
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Fires;
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Hurricanes,
tropical storms, earthquakes, mud slides, and
flooding;
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Pollution;
and
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Releases
of toxic gas.
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The
occurrence of one of the above may result in injury, loss of life, property
damage, 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 a 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
federal, state and local laws and regulations govern the environmental aspects
of our business and impose strict requirements for, among other
things:
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Well
drilling or workover, operation and
abandonment;
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·
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Waste
management;
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·
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Land
reclamation;
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·
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Financial
assurance under the Oil Pollution Act of 1990;
and
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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, other than certain retained claims, we are
responsible for environmental claims prior to the Acquisition and we may not
have indemnification from Calpine related to those claims.
Our
acquisition strategy could fail or present unanticipated problems for our
business in the future, which could adversely affect our ability to make
acquisitions or realize anticipated benefits of those
acquisitions.
Our
growth strategy includes acquiring oil and natural gas businesses and properties
if favorable economics and strategic objectives can be served. We may not be
able to identify suitable acquisition opportunities or finance and complete
any
particular acquisition successfully.
Furthermore,
acquisitions involve a number of risks and challenges, including:
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Division
of management’s attention;
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·
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The
need to integrate acquired
operations;
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Potential
loss of key employees of the acquired
companies;
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Potential
lack of operating experience in a geographic market of the acquired
business; and
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An
increase in our expenses and working capital
requirements.
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Any
of
these factors could adversely affect our ability to achieve anticipated levels
of cash flows from the acquired businesses and properties or realize other
anticipated benefits of those acquisitions.
We
are vulnerable to risks associated with operating in the Gulf of
Mexico.
Our
operations and financial results could be significantly impacted by conditions
in the Gulf of Mexico because we explore and produce extensively in that area.
As a result of this activity, we are vulnerable to the risks associated with
operating in the Gulf of Mexico, including those relating to:
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Adverse
weather conditions and natural
disasters;
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Oil
field service costs and
availability;
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Compliance
with environmental and other laws and
regulations;
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Remediation
and other costs resulting from oil spills or releases of hazardous
materials; and
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Failure
of equipment or facilities.
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Further,
production of reserves from reservoirs in the Gulf of Mexico generally decline
more rapidly than from fields in many other producing regions of the world.
This
results in recovery of a relatively higher percentage of reserves from
properties in the Gulf of Mexico during the initial years of production, and
as
a result, our reserve replacement needs from new prospects may be greater there
than for our operations elsewhere. Also, our revenues and return on capital
will
depend significantly on prices prevailing during these relatively short
production periods.
Hedging
transactions may limit our potential gains.
We
have
entered into natural gas price hedging arrangements with respect to a
significant portion of our expected production through 2009. Such transactions
may limit our potential gains if oil and natural gas prices were to rise
substantially over the price established by the hedge. In addition, such
transactions may expose us to the risk of loss in certain circumstances,
including instances in which our production is less than expected, there is
a
widening of price differentials between delivery points for our production
and
the delivery point assumed in the hedge arrangement, or the counterparties
to
our hedging agreements fail to perform under the contracts.
The
historical financial results of the domestic oil and natural gas business of
Calpine may not be representative of our results as a separate
company.
The
combined historical financial information included in this report does not
necessarily reflect what our financial position, results of operations and
cash
flows would have been had we been a separate, stand-alone entity during the
periods presented. The costs and expenses reflect charges from Calpine for
centralized corporate services and infrastructure costs. The allocations were
determined based on Calpine’s methodologies. This combined historical financial
information is not necessarily indicative of what our results of operations,
financial position and cash flows will be in the future.
Failure
to achieve and maintain effective internal control over financial reporting
in
accordance with the rules of the SEC could harm our
business.
Under
current rules of the SEC, as of December 31, 2007, we will be required to
document and test our internal control over financial reporting so that our
management can certify as to the effectiveness of our internal control over
financial reporting and our independent registered public accounting firm can
render an opinion on management’s assessment. We cannot be certain as to the
timing of completion of our evaluation, testing and remediation actions, if
any,
or the impact of the same on our operations. The assessment of our internal
control over financial reporting will require us to expend significant
management and employee time and resources and incur significant additional
expense.
We
have
begun the process of evaluating and documenting our internal control over
financial reporting in order to test and determine whether any remediation
actions may be necessary to fully implement the requirements relating to
internal controls and all other aspects of related SEC rules and the Sarbanes
Oxley Act of 2002. Management believes it has remediated the material weaknesses
noted as of December 31, 2005: (1) lack of a sufficient complement of permanent
personnel to have an appropriate accounting and financial reporting structure
to
support the activities of the Company and (2) ineffective controls as related
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; however, see Item 9A. Controls
and
Procedures, for a further discussion on these material weaknesses.
Although
we expect to fully implement the requirements to meet the required SEC and
Sarbanes-Oxley standards in 2007, our efforts may not be successful and
additional deficiencies or weaknesses in our internal controls and procedures
may be identified.
Our
prior and continuing relationship with Calpine exposes us to risks attributable
to Calpine’s businesses and credit worthiness.
We
acquired a business that previously was integrated within Calpine and is subject
to liabilities and risk for activities of businesses of Calpine other than
the
acquired business. In connection with our separation from Calpine, Calpine
and
certain of its subsidiaries have agreed to retain and indemnify us for certain
liabilities. Third parties may seek to hold us responsible for some or all
of
those retained liabilities.
Any
claims made against us that are properly attributable to Calpine and certain
of
its subsidiaries will require us to exercise our rights under the
indemnification provisions of the purchase and sale agreement to obtain payment
from them. We are exposed to the risk that, in these circumstances and in light
of the Calpine bankruptcy, any or all of Calpine and certain of its subsidiaries
cannot or will not make the required payment. If this were to occur, our
business and results of operations, financial position or cash flow could be
adversely affected.
If
we are unable to obtain governmental approvals arising from the Acquisition,
we
may not acquire all of Calpine’s domestic oil and gas
business.
The
consummation of the Acquisition required various approvals, filings and
recordings with governmental entities to transfer existing contracts and
arrangements as well as all of Calpine’s domestic oil and gas properties to us.
In addition, all government issued permits and licenses that are important
to
our business, including permits issued by the City of Rio Vista and Counties
of
Sacramento, Solano and Contra Costa, California, may require reapplication
or
application by us and reissuance or issuance in our name. Some of the required
permits, licenses and approvals have been obtained or received, but certain
others remain outstanding. If we are unable to obtain a reissuance or
issuance of any contract, license or permit being transferred or the required
approvals as operator and/or lessee, as to certain oil and gas properties,
our
business and results of operations, financial position and cash flow could
be
adversely affected.
The
SEC informal inquiry relating to the downward revision of the estimate of
continuing proved reserves, while owned by Calpine, could have a material
adverse effect on the presentation of our predecessor financial
statements.
In
April
2005, the staff of the Division of Enforcement of the SEC commenced an informal
inquiry into the facts and circumstances relating to the downward revision
of
the estimate of continuing proved natural gas reserves at December 31,
2004, while the domestic oil and natural gas properties were owned by Calpine.
Calpine has advised us that it is fully cooperating with this informal inquiry
which also involved two other non-oil and natural gas related matters, and
we
have separately agreed with Calpine that we will also fully cooperate. Calpine
has advised us that it has not had any further response or inquiry from the
SEC
staff in regard to this matter since July 2005 and that the ultimate outcome
of
this inquiry cannot presently be determined. However, it is possible that the
staff of the SEC could conclude that the estimate of continuing proved reserves
as of December 31, 2004, as revised, requires further downward revision,
which could have a material adverse effect on the presentation of our
predecessor financial statements.
Future
sales of our common stock may cause our stock price to
decline.
Sales
of
substantial amounts of our common stock in the public market, or the perception
that these sales may occur, could cause the market price of our common stock
to
decline, which could impair our ability to raise capital through the sale of
additional common or preferred stock.
Stock
sales and purchases by institutional investors or stockholders with significant
holdings could have significant influence over our stock volatility and our
corresponding ability to raise capital through debt or equity
offerings.
Because
institutional investors have the ability to trade in large volumes of shares
of
our common stock, the price of our common stock could be subject to significant
volatility, which could adversely affect the market price for our common stock
as well as limit our ability to raise capital or issue additional equity in
the
future.
You
may experience dilution of your ownership interests because of the future
issuance of additional shares of our common and preferred
stock.
We
may in
the future issue our previously authorized and unissued equity securities,
resulting in the dilution of the ownership interests of our present stockholders
and purchasers of common stock offered hereby. We are currently authorized
to
issue an aggregate of 155,000,000 shares of capital stock consisting of
150,000,000 shares of common stock and 5,000,000 shares of preferred stock
with
preferences and rights as determined by our Board of Directors. As of
December 31, 2006, 50,732,694 shares of common stock were issued, including
673,875 shares of restricted stock issued to certain employees and directors.
The majority of these vest over a three year period. Of the restricted stock
that has been granted, 346,975 shares had vested as of December 31, 2006 and
the
remaining shares will vest on a three year period ending in 2009. Pursuant
to
our 2005 Long-Term Incentive Plan, we have reserved 3,000,000 shares of our
common stock for issuance as restricted stock, stock options and/or other equity
based grants to employees and directors. Of the reserved shares, 1,233,333
may
be awarded as restricted stock and 1,766,667 may be awarded as stock options
and/or other equity based grants and includes 903,250 options to purchase common
stock issued to certain employees and directors, of which 50,396 have been
exercised as of December 31, 2006. The potential issuance of such additional
shares of common stock may create downward pressure on the trading price of
our
common stock. We may also issue additional shares of our common stock or other
securities that are convertible into or exercisable for common stock in
connection with the hiring of personnel, future acquisitions, future issuance
of
our securities for capital raising purposes, or for other business
purposes.
Provisions
under Delaware law, our certificate of incorporation and bylaws could delay
or
prevent a change in control of our company, which could adversely affect the
price of our common stock.
The
existence of some provisions under Delaware law, our certificate of
incorporation and bylaws could delay or prevent a change in control of the
Company, which could adversely affect the price of our common stock. Delaware
law imposes restrictions on mergers and other business combinations between
us
and any holder of 15% or more of our outstanding common stock. Our certificate
of incorporation and bylaws prohibit our stockholders from taking action by
written consent absent approval by all members of our Board of Directors.
Further, our stockholders do not have the power to call a special meeting of
stockholders.
Item
1B. Unresolved Staff Comments
None
Item
2. Properties
A
description of our properties is located in Item 1. Business and is incorporated
herein by reference.
Our
headquarters are located at 717 Texas, Suite 2800, Houston, Texas 77002, where
we sublease two floors of office space from Calpine. We also maintain a division
office in Denver, Colorado, where we were assigned a lease by Calpine and
consequently deal directly with the landlord. We also have field offices in
Laredo, Texas and Rio Vista, California. All leases were negotiated at market
prices applicable to their respective location.
Title
to Properties
Our
properties are subject to customary royalty interests, liens incident to
operating agreements, liens for current taxes and other burdens, including
other
mineral encumbrances and restrictions as well as mortgage liens on at least
80%
of our proved reserves in accordance with our credit facilities. We do not
believe that any of these burdens materially interferes with our use of the
properties in the operation of our business.
Except
as
noted in the “Transfers of Legal Title Pending at Calpine’s Bankruptcy” section
in Item 3. Legal Proceedings, we believe that we have generally satisfactory
title to or rights in all of our producing properties. As is customary in the
oil and natural gas industry, we make minimal investigation of title at the
time
we acquire undeveloped properties. We make title investigations and receive
title opinions of local counsel only before we commence drilling operations.
We
believe that we have satisfactory title to all of our other assets. Although
title to our properties is subject to encumbrances in certain cases, we believe
that none of these burdens will materially detract from the value of our
properties or from our interest therein or will materially interfere with our
use in the operation of our business.
Calpine’s
recent bankruptcy may delay or frustrate our ability to complete additional
transfers of properties for which legal title were not obtained as of
July 7, 2005.
Item
3. Legal Proceedings
We
are
party to various oil and natural gas litigation matters arising out of the
ordinary course of business. While the outcome of these proceedings cannot
be
predicted with certainty, we do not expect these matters to have a material
adverse effect on the financial statements.
We
carry
insurance with coverage and coverage limits consistent with our assessment
of
risks in our business and of an acceptable level of financial exposure. Although
there can be no assurance that such insurance will be sufficient to mitigate
all
damages, claims or contingencies, we believe that our insurance provides
reasonable coverage for known asserted or unasserted claims. In the event we
sustain a loss from a claim and the insurance carrier disputed coverage or
coverage limits, we may record a charge in a different period than the recovery,
if any, from the insurance carrier.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the Bankruptcy Court on December 20, 2005. Calpine
Energy Services, L.P., which filed for bankruptcy, has continued to make the
required deposits into 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 (“MSA”) with the Company. The MSA was entered into by the
Company and Calpine in July 2005 for the period through June 30,
2007.
The
filing raises certain concerns regarding aspects of our relationship with
Calpine which we will closely monitor as the Calpine bankruptcy proceeds. See
further discussion of our concerns under Item 1A. Risk Factors.
Transfers
of Legal Title 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
at the time of the Acquisition as requiring third party consents or waivers
of
preferential rights to purchase that were not received before closing. Legal
title for those Non-Consent Properties was not 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 legal 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 us for approximately $0.3 million for a property which was transferred
to
us but will be transferred to the appropriate third party should it properly
exercise its preferential purchase right and upon Calpine’s performance of its
remaining 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 for which a third party’s
preferential right to purchase was properly exercised) 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 legal
title and that such properties are not part of Calpine’s bankruptcy estate. Upon
our receipt from Calpine of record legal title, free of any mortgages or other
liens, to these Non-Consent Properties and Calpine’s performance or its 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 and
performance of Calpine’s obligations under the “further assurances” provisions
of the Purchase and Sale Agreement.
Our
statement of operations for the year ended December 31, 2006 and six months
ended December 31, 2005 does not include any net revenues or production from
any
of the Non-Consent Properties, or those properties subject to preferential
rights.
If
Calpine does not provide us with record legal 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 validly exercised
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 should that third party properly exercise their
preferential rights.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership. Requests
for additional documentation are customary in connection with transactions
similar to the Acquisition. In the Acquisition, certain of these properties
require ministerial governmental action approving us as qualified assignee
and
operator, which is typically required even though in most cases Calpine has
already conveyed the properties to us free and clear of mortgages and liens
by
Calpine’s creditors. As to certain other properties, the documentation delivered
by Calpine at closing under the Purchase Agreement was incomplete. We remain
hopeful that Calpine will work cooperatively with us to secure these ministerial
governmental approvals and to accomplish the curative corrections for all of
these properties. In addition, as to all properties acquired by us in the
Acquisition, Calpine contractually agreed to provide us with such further
assurances as we may reasonably request. Nevertheless, as a result of Calpine’s
bankruptcy filing, it remains uncertain as to whether Calpine will respond
cooperatively. If Calpine does not fulfill its contractual obligations and
does
not complete the documentation necessary to resolve these issues, we will pursue
all available remedies, including but not limited to a declaratory judgment
to
enforce our rights and actions to quiet title. After pursuing these matters,
if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome our
management considers to be remote, then we could experience losses which could
have a material adverse effect on our financial condition, statement of
operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases 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 it in order to avoid the automatic
forfeiture of any interest it may have in these leases by operation of a
statutory deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to us or Calpine, but we understand
it
was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy
Code of whatever interest Calpine may possess, if any, in these oil and natural
gas leases. We dispute Calpine’s contention that it may have an interest in any
significant portion of these oil and natural gas leases and intend to take
the
necessary steps to protect all of our rights and interest in and to the leases.
On July 7, 2006, we filed an objection in response to Calpine’s motion, wherein
we asserted that oil and natural gas leases constitute interests in real
property that are not subject to “assumption” under the Bankruptcy Code. In the
objection we also requested that (a) the Bankruptcy Court eliminate from the
order certain Federal offshore leases from the Calpine motion because these
properties were fully conveyed to us in July 2005, and the Minerals Management
Service has subsequently recognized us as owner and operator of all but three
of
these properties, and (b) any order entered by the Bankruptcy Court be without
prejudice to, and fully preserve our rights, claims and legal arguments
regarding the characterization and ultimate disposition of the remaining
described oil and natural gas properties. In our objection, we also urged the
Bankruptcy Court to require the parties to promptly address and resolve any
remaining issues under the pre-bankruptcy definitive agreements with Calpine
and
proposed to the Bankruptcy Court that the parties seek arbitration (or at least
mediation) to complete the following:
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Calpine’s
conveyance of the Non-Consent Properties to
us;
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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
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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.
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At
a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
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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
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The
Bankruptcy Court also encouraged Calpine and us to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent Properties.
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On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts as well as unliquidated damages in amounts that
can not presently be determined. We
continue to work with Calpine on a cooperative and expedited basis toward
resolution of unresolved conveyance of properties and post-closing adjustments
under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases, these
parties have further extended this deadline time by stipulation. The deadline
was first extended to January 31, 2007 and recently was further extended to
April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007
with respect to the CSLC Leases. The Bankruptcy Court entered Orders related
to
the MMS Oil and Gas Leases and CSLC Leases which included appropriate language
that we negotiated with Calpine for our protection in this regard.
Recently,
Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy
Court for the period in which only Calpine, exclusively, may file its plan
of
reorganization. While there is no assurance that Calpine will file a plan of
reorganization by the deadline, or that such a plan will be approved by the
creditors and the Bankruptcy Court, we remain optimistic that the issues
involving conclusion of the remaining conveyances of the Non-Consent Properties
and obtaining the further assurances from Calpine under the Purchase Agreement,
including perhaps resolution of any and all claims, may occur during
2007.
Calpine
recently requested Bankruptcy Court approval of a new credit facility which
would require it to grant liens to these new lenders in all of its assets,
including any interest it may still hold in any oil and gas properties it
obligated itself to convey to us under the Purchase Agreement. The Bankruptcy
Court entered into an Order approving Calpine’s ability to obtain this new loan
which includes appropriate language that we negotiated with Calpine for our
protection in this regard.
However,
there can be no assurance that Calpine, its creditors or other interest holders
will not challenge the fairness of the Acquisition. For a number of reasons,
including our understanding of the process that Calpine followed in allowing
market forces to set the purchase price for the Acquisition, we continue to
believe that it is unlikely that any challenges by the Calpine debtors or their
creditors to the overall fairness of the Acquisition would be successful. We
will take all necessary action to ensure our rights under the Purchase
Agreement, the MMS Oil and Gas Leases, the CSLC Leases and the Bankruptcy Code
are fully protected.
Item
4. Submission of Matters to a Vote of Security
Holders
No
matters were submitted to a vote of our security holders during the fourth
quarter of 2006.
Part
II
Item
5. Market for Registrant’s Common Equity, Related
Stockholder Matters and Issuer Purchases of Equity
Securities
Trading
Market
Our
common stock is listed on The NASDAQ Global Select Market®
under
the symbol “ROSE”. Our common stock began publicly trading on
February 13, 2006. Prior to such date, there was no public market for our
common stock. However, certain qualified institutional investors participated
in
limited trading through quotes on The PORTAL Market after July 7, 2005.
The
following table sets forth for the 2006 periods indicated the high and low
sale
prices of our common stock:
|
High
|
Low
|
||||||
|
February
13 - March 31
|
$
|
18.75
|
$
|
17.67
|
|||
|
April
1 - June 30
|
21.48
|
15.81
|
|||||
|
July
1 - September 30
|
19.05
|
15.82
|
|||||
|
October
1 - December 31
|
19.89
|
16.71
|
|||||
The
number
of
shareholders on March 5, 2007 was 13,444. However, we estimate that we have
a
significantly greater number of beneficial shareholders because a substantial
number of our common shares are held of record by brokers or dealers for the
benefit of their customers.
We
have
not paid a cash dividend on our common stock and currently intend to retain
earnings to fund the growth and development of our business. Any future change
in our policy will be made at the discretion of our board of directors in light
of the financial condition, capital requirements, earnings prospects of Rosetta
and any limitations imposed by lenders or investors, as well as other factors
the board of directors may deem relevant.
The
following table sets forth certain information with respect to repurchases
of
our common stock during the three months ended December 31, 2006:
|
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
|
|||||||||
|
October
1 - October 31
|
945
|
$
|
17.93
|
-
|
-
|
||||||||
|
November
1 - November 30
|
962
|
19.15
|
-
|
-
|
|||||||||
|
December
1 - December 31
|
-
|
-
|
-
|
-
|
|||||||||
|
(1)
|
All
of the shares were surrendered by the 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
common stock.
|
Stock
Performance Graph
The
following graph compares our common stock performance (“ROSE”) with the
performance of the Standard & Poors’ 500 Stock Index (“S&P 500 Index”)
and the performance of our peers within the oil and gas industry. The seven
companies that comprise our peer group are Petrohawk Energy Corporation (HAWK),
St. Mary Land & Exploration Co. (SM), Bill Barrett Corp. (BBG), Brigham
Exploration Co. (BEXP), Berry Petroleum Co. (BRY), Comstock Resources Inc.
(CRK)
and Range Resources Corp. (RRC), (“Peer Group”). The graph assumes the value of
the investment in our common stock , the S&P 500 Index, and our Peer Group
was $100 on February 13, 2006 and that all dividends are reinvested.
The
performance graph shall not be deemed incorporated by reference by any general
statement incorporating by reference this Annual Report into any filing under
the Securities Act of 1933, except to the extent we specifically incorporate
this information by reference and shall not otherwise be deemed filed under
such
acts.
Total
Return Among Rosetta Resources, Inc., the S&P 500 Index and our Peer
Group
|
2/13/2006
(1)
|
12/31/2006
|
||||||
|
ROSE
|
$
|
100.00
|
$
|
98.26
|
|||
|
S&P
500 Index
|
$
|
100.00
|
$
|
111.94
|
|||
|
Peer
Group
|
$
|
100.00
|
$
|
94.82
|
|||
(1)
February 13, 2006 was the first full trading day following the effective date
of
the Company’s registration statement filed in connection with the public
offering of its common stock.
Item
6. Selected Financial Data
The
following table sets forth our selected financial data. For the year ended
December 31, 2006 (Successor) and the six months ended December 31, 2005
(Successor), the financial data has been derived from the consolidated financial
statements of Rosetta Resources Inc. For the six months ended June 30, 2005
(Predecessor) and for the years ended December 31, 2004, 2003 and 2002
(Predecessor), the financial data was derived from the combined financial
statements of the domestic oil and natural gas properties of Calpine and are
presented on a carve-out basis to include the historical operations of the
domestic oil and natural gas business. You should read the following selected
historical consolidated/combined financial data in connection with “Management’s
Discussion and Analysis of Financial Condition and Results of Operation” and the
audited Consolidated/Combined Financial Statements and related notes included
elsewhere in this report.
Additionally,
the historical financial data reflects successful efforts accounting for oil
and
natural gas properties for the Predecessor periods described above and the
full
cost method of accounting for oil and natural gas properties effective
July 1, 2005 for the Successor periods. In addition, Calpine adopted on
January 1, 2003, 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”) 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 pursuant to Accounting Principles Board Opinion No. 25,
“Stock Issued to Employees” (“APB No. 25”) effective July 2005, and as
required have adopted the guidance for stock-based compensation under SFAS
No.
123 (revised 2004) “Share-Based Payments” (“SFAS No. 123R”) effective January 1,
2006.
|
Successor-Consolidated
|
Predecessor
- Combined
|
||||||||||||||||||||
|
Year
Ended
December
31,
|
Six
Months Ended
December
31,
|
Six
Months Ended
June
30,
|
Year
Ended
December
31,
|
||||||||||||||||||
|
2006
|
2005
|
2005
|
2004
|
2003
|
2002
|
||||||||||||||||
|
(In
thousands, except per share data)
|
|||||||||||||||||||||
|
Operating
Data:
|
|||||||||||||||||||||
|
Total
revenue
|
$
|
271,763
|
$
|
113,104
|
$
|
103,831
|
$
|
248,006
|
$
|
279,916
|
$
|
157,372
|
|||||||||
|
Income
(loss) from continuing operations (1)
|
44,608
|
17,535
|
18,681
|
(78,836
|
)
|
66,879
|
1,484
|
||||||||||||||
|
Net
income (loss)
|
44,608
|
17,535
|
18,681
|
(10,396
|
)
|
71,440
|
(168
|
)
|
|||||||||||||
|
Income
per share:
|
|||||||||||||||||||||
|
Income
(loss) from continuing operations
|
|||||||||||||||||||||
|
Basic
|
0.89
|
0.35
|
0.37
|
(1.58
|
)
|
1.34
|
0.03
|
||||||||||||||
|
Diluted
|
0.88
|
0.35
|
0.37
|
(1.58
|
)
|
1.33
|
0.03
|
||||||||||||||
|
Net
income (loss)
|
|||||||||||||||||||||
|
Basic
|
0.89
|
0.35
|
0.37
|
(0.21
|
)
|
1.43
|
-
|
||||||||||||||
|
Diluted
|
0.88
|
0.35
|
0.37
|
(0.21
|
)
|
1.42
|
-
|
||||||||||||||
|
Cash
dividends declared per common share
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||
|
Balance
Sheet Data (At the end of the Period)
|
|||||||||||||||||||||
|
Total
assets
|
1,219,405
|
1,119,269
|
-
|
656,528
|
990,893
|
940,619
|
|||||||||||||||
|
Long-term
debt
|
240,000
|
240,000
|
-
|
-
|
507
|
684
|
|||||||||||||||
|
Stockholders'
equity/owner's net investment
|
822,289
|
715,423
|
-
|
223,451
|
233,847
|
162,407
|
|||||||||||||||
____________________
|
(1)
|
Includes
a $202.1 million impairment charge for the year ended December
31,
2004.
|
Item
7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
We
are
an
independent oil and natural gas company engaged in the acquisition, exploration,
development and production of natural gas and oil properties in the United
States. We were formed as a Delaware corporation in June 2005. In July 2005,
we
acquired the oil and natural gas business of Calpine Corporation and affiliates.
We own producing and non-producing oil and natural gas properties in the
Sacramento Basin of California, the Lobo and Perdido Trends in South Texas,
the
State Waters of Texas, the Gulf of Mexico, the Rocky Mountains and other
properties located in various geographical areas in the United States. In this
section, we refer to Rosetta as “Successor” and to the domestic oil and natural
gas properties acquired from Calpine as “Predecessor”.
In
accounting for the oil and natural gas exploration and production business,
the
Predecessor used the successful efforts method of accounting for oil and natural
gas activities. However, in connection with our separation from Calpine, we
have
adopted the full cost method of accounting for our oil and natural gas
properties, (see “Critical Accounting Policies and Estimates—Oil and Gas
Activities” below for further discussion of the differences on the
Consolidated/Combined Financial Statements of the two accounting
methods).
We
plan
our activities and budget based on conservative sales price assumptions given
the inherent volatility of oil and natural gas prices that are influenced by
many factors beyond our control. We focus our efforts on increasing oil and
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 the fair market value of hedges we executed to mitigate the
volatility in the changes of oil and natural gas prices in future periods.
These
instruments meet the criteria to be accounted for as cash flow hedges, and
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 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. Because of our relatively small size and
concentrated property base, we can be disproportionately disadvantaged by delays
in obtaining or failing to obtain drilling approvals compared to companies
with
larger or more diverse 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 or foregone opportunities resulting from
delays.
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. As such, our
operating income does not
include volumes and revenues related to these oil and natural gas properties
not
conveyed by Calpine. The total SEC PV-10 value of these wells and the associated
leases was $53.0 million pretax at December 31, 2006.
Financial
Highlights
The
Consolidated Financial Statements reflect total revenue of $271.8 million on
total volumes of 33.4 Bcfe for the year ended December 31, 2006
(Successor). Operating income was $85.1 million or 31% of total revenue and
included workover costs of approximately $6.5 million and $5.7 million of
compensation expense for stock-based compensation granted to employees. Total
net other income was comprised of interest expense (net of capitalized interest)
on our credit facility offset by interest income on short term cash investments.
Overall, our net income for the year ended December 31, 2006 (Successor)
was $44.6 million or 16% of total revenue.
Critical
Accounting Policies and Estimates
The
discussion and analysis of our financial condition and results of operations
are
based upon the Consolidated/Combined Financial Statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States of America. The preparation of these financial statements requires
us to make estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses, related disclosure of contingent assets
and
liabilities and proved oil and gas reserves. Certain accounting policies involve
judgments and uncertainties to such an extent that there is reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been used. We evaluate
our
estimates and assumptions on a regular basis. We base our estimates on
historical experience and various other assumptions that are believed to be
reasonable under the circumstances, the results of which form the basis for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results may differ from these
estimates and assumptions used in preparation of our financial statements.
Below, we have provided expanded discussion of our more significant accounting
policies, estimates and judgments for our financial statements and those of
our
Predecessor. We believe these accounting policies reflect the more significant
estimates and assumptions used in preparation of the financial
statements.
We
also
describe the most significant estimates and assumptions we make in applying
these policies. See Item 8. Consolidated Financial Statements and Supplementary
Data Note 3, Summary
of Significant Accounting Policies,
for a
discussion of additional accounting policies and estimates made by
management.
Oil
and Gas Activities
Accounting
for oil and gas activities is subject to special, unique rules. Two generally
accepted methods of accounting for oil and gas activities are available which
include the successful efforts method or the full cost method. The most
significant differences between these two methods are the treatment of
exploration costs and the manner in which the carrying value of oil and gas
properties are amortized and evaluated for impairment. The successful efforts
method, as used by our Predecessor, requires exploration costs to be expensed
as
they are incurred while the full cost method provides for the capitalization
of
these costs. Both methods generally provide for the periodic amortization of
capitalized costs based on proved reserve quantities. Impairment of oil and
gas
properties under the successful efforts method is based on an evaluation of
the
carrying value of individual oil and gas properties against their estimated
fair
value. For the year ended December 31, 2004, our Predecessor recorded a $202.1
million impairment related to a reduction of proved reserve projections based
on
the year-end independent engineers report. The assessment for impairment under
the full cost method requires an evaluation of the carrying value of oil and
gas
properties included in a cost center against the net present value of future
cash flows from the related proved reserves, using period-end prices and costs
and a 10% discount rate.
Full
Cost Method
We
use
the full cost method of accounting for our oil and gas activities. Under this
method, all costs incurred in the acquisition, exploration and development
of
oil and gas properties are capitalized into a cost center (the amortization
base), whether or not the activities to which they apply are successful. Such
amounts include the cost of drilling and equipping productive wells, dry hole
costs, lease acquisition costs and delay rentals. Capitalized costs also include
salaries, employee benefits, costs of consulting services and other expenses
that are estimated to directly relate to our oil and gas activities. Interest
costs related to unproved properties are also capitalized. Although some of
these costs will ultimately result in no additional reserves, we expect the
benefits of successful wells to more than offset the costs of any unsuccessful
ones. Costs associated with production and general corporate activities are
expensed in the period incurred. The capitalized costs of our oil and gas
properties, plus an estimate of our future development and abandonment costs,
are amortized on a unit-of-production method based on our estimate of total
proved reserves. Unevaluated costs are excluded from the full cost pool and
are
periodically considered for impairment rather than amortization. Upon
evaluation, these costs are transferred to the full cost pool and amortized.
Our
financial position and results of operations would have been significantly
different had we used the successful efforts method of accounting for our oil
and gas activities, as used by our Predecessor, and as presented herein for
the
six months ended June 30, 2005 and the year ended December 31, 2004, since
we
generally reflect a higher level of capitalized costs as well as a higher
depreciation, depletion and amortization rate on our oil and natural gas
properties.
Proved
Oil and Gas Reserves
Our
engineering estimates of proved oil and gas reserves directly impact financial
accounting estimates, including depreciation, depletion and amortization expense
and the full cost ceiling limitation. Proved oil and gas reserves are the
estimated quantities of oil and gas reserves that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under period-end economic and operating conditions. The
process of estimating quantities of proved reserves is very complex, requiring
significant subjective decisions in the evaluation of all geological,
engineering and economic data for each reservoir. Accordingly, our reserve
estimates are developed internally and subsequently, provided to a third party
engineering firm who then generates an annual year-end reserve report. The
data
for a given reservoir may change substantially over time as a result of numerous
factors including additional development activity, evolving production history
and continual reassessment of the viability of production under varying economic
conditions. Changes in oil and gas prices, operating costs and expected
performance from a given reservoir also will result in revisions to the amount
of our estimated proved reserves. The estimate of proved oil and natural gas
reserves primarily impact property, plant and equipment amounts in the balance
sheets and the depreciation, depletion and amortization amounts in the
consolidated/combined statement of operations, among other items. For more
information regarding reserve estimation, including historical reserve
revisions, refer to Item 8. Consolidated Financial Statements and
Supplementary Data, Supplemental
Oil and Gas Disclosure.
Depreciation,
Depletion and Amortization
The
quantities of estimated proved oil and gas reserves are a significant component
of our calculation of depletion expense and revisions in such estimates may
alter the rate of future expense. Holding all other factors constant, if
reserves are revised upward, earnings would increase due to lower depletion
expense. Likewise, if reserves are revised downward, earnings would decrease
due
to higher depletion expense or due to a ceiling test write-down. A five percent
positive or negative revision to proved reserves throughout the Company would
decrease or increase the depreciation, depletion and amortization rate by
approximately $0.12 to $0.13 per MMcfe. This estimated impact is based on
current data at December 31, 2006 and actual events could require different
adjustments to depreciation, depletion and amortization.
Full
Cost Ceiling Limitation
Our
ceiling test computation was calculated using hedge adjusted market prices
at
December 31, 2006 which were based on a Henry Hub price of $5.64 per MMBtu
and a
West Texas Intermediate oil price of $60.50 per Bbl (adjusted for basis and
quality differentials). The use of these prices would have resulted in an
after-tax writedown of $85 million at December 31, 2006. Cash flow hedges of
natural gas production in place at December 31, 2006 increased the calculated
ceiling value by approximately $47 million (net of tax). However, subsequent
to
December 31, 2006 the market price for Henry Hub increased to $7.52 per MMBtu
and the price for West Texas Intermediate increased to $61.84 per Bbl, and
utilizing these prices our net capitalized costs of oil and gas properties
exceeded the ceiling amount. As a result no writedown was recorded at December
31, 2006. The ceiling value calculated using subsequent prices includes
approximately $6 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 prices decline in the future, it is possible that a writedown
could occur.
There
was
no ceiling test writedown for the six months ended December 31,
2005.
Future
Development and Abandonment Costs
Future
development costs include costs incurred to obtain access to proved reserves
such as drilling costs and the installation of production equipment. Future
abandonment costs include costs to dismantle and relocate or dispose of our
production platforms, gathering systems and related structures and restoration
costs of land and seabed. We develop estimates of these costs for each of our
properties based upon their geographic location, type of production structure,
well depth, currently available procedures and ongoing consultations with
construction and engineering consultants. Because these costs typically extend
many years into the future, estimating these future costs is difficult and
requires management to make judgments that are subject to future revisions
based
upon numerous factors, including changing technology and the political and
regulatory environment. We review our assumptions and estimates of future
development and future abandonment costs on an annual basis.
We
provide for future abandonment costs in accordance with SFAS
No. 143,“Accounting
for Asset Retirement Obligations”. This standard requires that a liability for
the discounted fair value of an asset retirement obligation be recorded in
the
period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability
is
accreted to its present value each period, and the capitalized cost is
depreciated over the useful life of the related asset. Holding all other factors
constant, if our estimate of future abandonment and development costs is revised
upward, earnings would decrease due to higher depreciation, depletion and
amortization (DD&A) expense. Likewise, if these estimates are revised
downward, earnings would increase due to lower DD&A expense.
Income
Taxes
We
provide for deferred income taxes on the difference between the tax basis of
an
asset or liability and its carrying amount in our financial statements in
accordance with SFAS No. 109, “Accounting for Income Taxes”. This difference
will result in taxable income or deductions in future years when the reported
amount of the asset or liability is recovered or settled, respectively.
Considerable judgment is required in determining when these events may occur
and
whether recovery of an asset is more likely than not. Deferred tax assets are
reduced by a valuation allowance when, in the opinion of management, it is
more
likely than not that some portion or all of the deferred tax assets will not
be
realized.
Estimating
the amount of the valuation allowance is dependent on estimates of future
taxable income, alternative minimum tax income and change in stockholder
ownership that would trigger limits on use of net operating losses under the
Internal Revenue Code Section 382. We have a significant deferred tax asset
associated with net operating loss carryforwards (NOLs). It is more likely
than
not that we will use these NOLs to offset current tax liabilities in future
years. Our NOLs are more fully described in “Item 8. Financial Statements and
Supplementary Data - Note 13.
Additionally,
our federal and state income tax returns are generally not filed before the
Consolidated Financial Statements are prepared, therefore we estimate the tax
basis of our assets and liabilities at the end of each period as well as the
effects of tax rate changes, tax credits and net operating and capital loss
carryforwards and carrybacks. Adjustments related to differences between the
estimates we used and actual amounts we reported are recorded in the period
in
which we file our income tax returns. These adjustments and changes in our
estimates of asset recovery could have an impact on our results of operations.
A
one percent change in our effective tax rate would have affected our calculated
income tax expense by approximately $0.7 million for the year ended December
31,
2006.
Derivative
Transactions and Hedging Activities
We
enter
into derivative transactions to hedge against changes in oil and natural gas
prices from time to time primarily through the use of fixed price swap
agreements, costless collars, and put options. Consistent with our hedge policy,
we entered into a series of natural gas fixed-price swaps and costless collars
for a significant portion of our expected natural gas production through 2009.
These transactions are recorded in our financial statements in accordance with
SFAS No. 133, “Accounting for Derivative Instruments and Hedging
Activities” (“SFAS No. 133”). Although not risk free, we believe this
policy will reduce our exposure to commodity price fluctuations and thereby
achieve a more predictable cash flow. We do not enter into derivative agreements
for trading or other speculative purposes.
In
accordance with SFAS No. 133, as amended, all derivative instruments,
unless designated as normal purchase normal sale, are recorded on the balance
sheet at fair market value and changes in the fair market value of the
derivatives are recorded each period in current earnings or other comprehensive
income, depending on whether a derivative is designated as a hedge transaction,
and depending on the type of hedge transaction. Our derivative contracts are
cash flow hedge transactions in which we are hedging the variability of cash
flow related to a forecasted transaction. Changes in the fair market value
of
these derivative instruments are reported in other comprehensive income and
reclassified as earnings in the period(s) in which earnings are impacted by
the
variability of the cash flow of the hedged item. We assess the effectiveness
of
hedging transactions quarterly, consistent with our documented risk management
strategy for the particular hedging relationship. Changes in the fair market
value of the ineffective portion of cash flow hedges are included in other
income (expense).
Stock
-Based Compensation
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 year ended December 31, 2004 and 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 our accounting policies, we chose to apply the intrinsic value
method pursuant to APB No. 25 effective July 2005, and as required have
adopted the guidance for stock-based compensation under SFAS No. 123R effective
January 1, 2006.
SFAS
No.
123R 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 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. 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 No. 123.
Recent
Accounting Developments
The
Fair Value Option for Financial Assets and Financial
Liabilities.
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option For
Financial Assets and Financial Liabilities - Including an Amendment of FASB
Statement No. 115” (“SFAS No. 159), which permits an entity to choose to measure
certain financial assets and liabilities at fair value. SFAS No. 159 also
revises provisions of SFAS No. 115 that apply to available-for-sale and trading
securities. This statement is effective for fiscal years beginning after
November 15, 2007. The Company has not yet evaluated the potential impact
of this standard.
Fair
Value Measurements.
In
September 2006, the FASB issued SFAS No. 157,“Fair
Value Measurements” (“SFAS No. 157”), which addresses how companies should
measure fair value when companies are required to use a fair value measure
for
recognition or disclosure purposes under generally accepted accounting
principles (“GAAP”). As a result of SFAS No. 157, there is now a common
definition of fair value to be used throughout GAAP. SFAS No. 157 is effective
for financial statements issued for fiscal years beginning after November 15,
2007, and interim periods within those years. Although the disclosure
requirements may be expanded where certain assets or liabilities are fair
valued, 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. We are still assessing the impact of this standard
but we do not expect the adoption of this standard to have a material impact
on
our consolidated financial position, results of operations, or cash
flows.
Guidance
for Quantifying Financial Statement Misstatement.
In
September 2006, the 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 used the iron curtain method for quantifying financial
statement misstatements. The Company has applied 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 did not 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. We are
evaluating our tax positions and anticipate that the interpretation will not
have a significant impact on the Company’s retained earnings at the time of
adoption.
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.
Results
of Operations
Due
to
the acquisition of Calpine Natural Gas L.P. in July 2005, the year ended
December 31, 2006 financial data is not comparative with 2005 or 2004. As such,
the results of operations for the year ended December 31, 2005 are presented
in
two periods, Successor comprising the six months ended December 31, 2005 and
Predecessor comprising the six months ended June 30, 2005. The results of
operations for the year ended December 31, 2004 are also shown as Predecessor.
See Note 2 to the Consolidated/Combined Financial Statements for the summary
pro
forma effect of the Acquisition for the years ended December 31, 2005 and
2004.
Differences
in accounting principles also exist between us and Calpine, 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 to measure the cost of employee services received in exchange for
an award of equity instruments at fair value, 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. See Note 3 to
the Consolidated/Combined Financial Statements for further discussion regarding
the adoption of SFAS 123R.
We
believe comparative results would be misleading and, therefore, have presented
the information below separately as Successor and Predecessor.
|
Successor-Consolidated
|
Predecessor-Combined
|
||||||||||||||
|
Year
Ended
December
31, 2006
|
Six
Months Ended
December
31, 2005
|
Six
Months Ended
June
30, 2005
|
Year
Ended
December
31, 2004
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
|||||||||||||||
|
Total
revenues
|
$
|
271,763
|
$
|
113,104
|
$
|
103,831
|
$
|
248,006
|
|||||||
|
Production:
|
|||||||||||||||
|
Gas
(Bcf)
|
30.3
|
12.4
|
14.5
|
37.3
|
|||||||||||
|
Oil
(MBbls)
|
551.3
|
185.6
|
163.8
|
600.0
|
|||||||||||
|
Total
Equivalents (Bcfe)
|
33.4
|
13.5
|
15.5
|
40.9
|
|||||||||||
|
$
per unit:
|
|||||||||||||||
|
Avg.
Gas Price per Mcf
|
$
|
7.81
|
$
|
8.23
|
$
|
6.59
|
$
|
6.02
|
|||||||
|
Avg.
Gas Price per Mcf excluding Hedging
|
6.83
|
9.57
|
-
|
-
|
|||||||||||
|
Avg.
Oil Price per Bbl
|
64.01
|
59.52
|
49.86
|
39.08
|
|||||||||||
|
Avg.
Revenue per Mcfe
|
$
|
8.14
|
$
|
8.38
|
$
|
6.70
|
$
|
6.06
|
|||||||
Revenues
Year
Ended December 31, 2006 (Successor)
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 $271.8
million for the year ended December 31, 2006 consists primarily of natural
gas
sales comprising 87% of total revenue on total volumes of 33.4 Bcfe.
Natural
Gas.
Natural
gas sales revenue was $236.5 million, including the effects of hedging, based
on
total gas production volumes of 30.3 Bcf. Approximately 75% of the production
volumes were from the following three areas: California, Lobo, and Perdido.
Average natural gas prices were $7.81 for the respective period. The effect
of
hedging on natural gas sales revenue was an increase of $29.6 million for an
increase in total price from $6.83 to $7.81 per Mcf.
Crude
Oil.
Oil
sales revenue was $35.3 million for the year ended December 31, 2006 with oil
production volumes of 551.3 MBbls. The oil production volumes were primarily
in
the Offshore and Other Onshore regions with approximately 75% of the total
production volumes. The average oil price was $64.01 per Bbl for the year ended
December 31, 2006.
Six
Months Ended December 31, 2005 (Successor)
Total
revenue of $113.1 million for the six months ended December 31, 2005
consists primarily of natural gas sales comprising 90% of total revenue on
total
volumes of 13.5 Bcfe.
Natural
Gas. Natural
gas sales revenue was $102.1 million, including the effects of hedging, based
on
total gas production volumes of 12.4 Bcf. Lobo and Perdido production was 3.9
Bcf and 1.5 Bcf or 28.9% and 11.2%, respectively, or a total of 5.4 Bcf and
40.1% of total volumes. California production was 5.3 Bcf or 39.0% of total
volumes at a average price of $9.08 per Mcfe, excluding the effects of hedging.
California production was affected by the delay in our drilling program and
compression issues. The effect of hedging on natural gas sales revenue was
a
decrease of $16.6 million related to volumes of 8.0 MMBtu for a decrease in
total price to $8.23 per Mcf.
Crude
Oil. Oil
revenue was $11.0 million based on oil production volumes of 185.6 MBbls. The
Southern region production was 21.9 MBbls, 8.5 MBbls, 8.3 MBbls, 42.0 MBbls
and
93.0 MBbls from Lobo, Perdido, State Waters, Other Onshore and Gulf of Mexico
or
94% of oil production for the six months ended December 31, 2005 at a total
average price of $59.61 per Bbl for these fields. Overall volumes in the Gulf
of
Mexico were affected by Hurricanes Katrina and Rita. In addition, production
volumes were also affected by a workover program at High Island and East Cameron
which was delayed in prior years due to capital constraints imposed by Calpine.
Fluctuations in product prices significantly impacted our revenue from existing
properties.
Six
Months Ended June 30, 2005 (Predecessor)
Total
revenue of $103.8 million for the six months ended June 30, 2005 consists
primarily of natural gas sales comprising 92% of total revenue on total volumes
of 15.5 Bcfe.
Natural
Gas.
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.
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.
Year
Ended December 31, 2004 (Predecessor)
Total
revenue of $248.0 million for the year ended December 31, 2004 consists
primarily of natural gas sales comprising 91% of total revenue on total volumes
of 40.9 Bcfe.
Natural
Gas.
Natural
gas sales revenue was $224.6 million with natural gas production volumes of
37.3
Bcf for the year ended December 31, 2004. The production volumes were lower
than
expected due to the capital constraints of our Predecessor which impacted the
exploration and development program. The average price for natural gas was
$6.02
per Mcf.
Crude
Oil.
For the
year ended December 31, 2004, oil sales revenue was $23.4 million based on
production volumes of 600.0 MBbls. The production volumes were primarily from
the offshore area in the Gulf of Mexico. The average oil price was $39.08 per
Bbl for the year ended December 31, 2004.
Operating
Expenses
The
following table presents information about our operating expenses:
|
Successor-Consolidated
|
Predecessor-Combined
|
||||||||||||||
|
Year
Ended
December
31, 2006
|
Six
Months Ended
December
31, 2005
|
Six
Months Ended
June
30, 2005
|
Year
Ended
December
31, 2004
|
||||||||||||
|
(In
thousands, except per unit amounts)
|
|||||||||||||||
|
Lease
operating expense
|
$
|
36,273
|
$
|
15,674
|
$
|
16,629
|
$
|
30,785
|
|||||||
|
Depreciation,
depletion and amortization
|
105,886
|
40,500
|
30,679
|
81,590
|
|||||||||||
|
Impairment
|
-
|
-
|
-
|
202,120
|
|||||||||||
|
General
and administrative costs
|
$
|
33,233
|
$
|
14,687
|
$
|
9,677
|
$
|
19,416
|
|||||||
|
$
per unit:
|
|||||||||||||||
|
Avg.
lease operating expense per Mcfe
|
$
|
1.09
|
$
|
1.16
|
$
|
1.08
|
$
|
0.75
|
|||||||
|
Avg.
DD&A per Mcfe (Excluding impairments)
|
3.17
|
3.00
|
1.98
|
2.00
|
|||||||||||
|
Avg.
G&A per Mcfe
|
$
|
1.00
|
$
|
1.09
|
$
|
0.63
|
$
|
0.48
|
|||||||
Year
Ended December 31, 2006 (Successor)
Lease
Operating Expense.
Lease
operating expense of $36.3 million related directly to oil and gas volumes
which
totaled 33.4 Bcfe for the year ended December 31, 2006 or costs of $1.09 per
Mcfe. Lease operating costs were affected by the wells that came on-line in
South Texas. Lease operating expense includes workover costs of $0.19 per Mcfe,
ad valorem taxes of $0.20 per Mcfe and insurance of $0.04 per Mcfe.
Depreciation,
Depletion and Amortization.
Depreciation, depletion and amortization was $105.9 million for the year ended
December 31, 2006 under the full cost method of accounting. The depletion rate
was $3.10 per Mcfe.
General
and Administrative costs. For
the
year ended December 31, 2006, general and administrative costs were $33.2
million, net of capitalization of certain general and administrative costs
of
$3.4 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 year ended December 31, 2006 was $5.7 million
and
is included in general and administrative costs.
Six
Months Ended December 31, 2005 (Successor)
Lease
Operating Expense.
Our
lease operating expense of $15.7 million is primarily due to oil and natural
gas
volumes which totaled 13.5 Bcfe for the six months ended December 31, 2005
or
costs of $1.16 per Mcfe. The costs include workover costs on our High Island
A-442 and East Cameron 88 wells in the Gulf of Mexico and the La Perla field
in
South Texas. Lease operating costs included workover costs, ad valorem taxes
and
insurance of $0.22 per Mcfe, $0.25 per Mcfe and $0.04 per Mcfe,
respectively.
Depreciation,
Depletion and Amortization.
Depreciation, depletion and amortization expense was $40.5 million for the
six
months ended December 31, 2005. We adopted the full cost method of
accounting for oil and gas properties as further discussed in our “Critical
Accounting Policies and Estimates” above whereby related costs are capitalized
into the full cost pool. Our depletion rate for this period was an average
of
$3.00 per Mcfe. There were no ceiling test write-downs for the six months ended
December 31, 2005.
General
and Administrative Costs.
General
and administrative costs of $14.7 million is net of capitalization of general
and administrative costs of $3.5 million as a component of our oil and natural
gas properties under the full cost method of accounting for oil and natural
gas
properties which we adopted July 1, 2005. General and administrative costs
for this period include $4.2 million of stock compensation expense for stock
granted to employees during the period and $10.9 million of salary and employee
benefit costs before capitalization of any of these costs to our oil and natural
gas properties.
Six
Months Ended June 30, 2005 (Predecessor)
Lease
Operating Expense. Lease
Operating Expense was $16.6 million and related to total oil and gas volumes
of
15.5 Bcfe or $1.08 per Mcfe for the six months ended June 30, 2005. Lease
operating 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. These costs are due to higher
taxes in South Texas and a special reclamation tax in California.
Depreciation,
Depletion and Amortization.
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 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.
Year
Ended December 31, 2004 (Predecessor)
Lease
Operating Expense.
For the
year ended December 31, 2004, lease operating expense was $30.8 million or
$0.75
per Mcfe. These expenses primarily related to non-operated lease expense
associated with drilling activity in the Impac field in South Texas operated
by
EOG Resources, Inc. Lease operating expenses also include items such as costs
related to salt water disposal (primarily in California), supervisory and labor
costs, ad valorem taxes and well servicing costs.
Depreciation,
Depletion and Amortization.
The
depreciation, depletion and amortization expense of $81.6 million primarily
related to the addition of 20 new wells in the Impac field in South Texas during
2004. Under successful efforts accounting, depletion expense is separately
computed for each field. The capital expenditures for proved properties for
each
field compared to the proved reserves corresponding to each field to determine
a
depletion rate for current production. The DD&A rate in South Texas was
approximately $3.50 per Mcfe in 2004 as the costs associated with drilling
these
wells increased significantly relative to the reserves added during the
period.
Impairment.
During
2004, our Predecessor revised downward its estimate of proved reserves by a
total of approximately 58 Bcfe, or 12% as of December 31, 2004.
Approximately 69% of the total revision was attributable to the downward
revision of the estimate of proved reserves in the South Texas fields and to
a
smaller extent unanticipated well performance decline in offshore fields. The
remaining 31% of the total revision was primarily due to the downward revision
of our Predecessor’s estimate of proved reserves in California of 17%, Other
Onshore of 10% and Gulf of Mexico of 4%. The downward revisions of our
predecessor’s estimates were based on the independent reservoir engineer’s
year-end reserve report, which reflected production results and drilling
activity that occurred during 2004 and used historical field level decline
curves. Due to significant capital constraints by our Predecessor, drilling
activity was minimized and correspondingly the estimate of proved reserves
could
not be supported through drilling success or future capital activity and the
downward revision was required. In addition, under the successful efforts method
of accounting for oil and natural gas properties, individual assets are grouped
at the lowest level for which there are identifiable cash flows. With minimal
drilling activity and the evaluation of cash flows at this level, proved
reserves for South Texas and California fields and the Gulf of Mexico had to
be
revised downward at each individual field level. As a result of the decreases,
primarily in proved undeveloped reserves, a non-cash impairment charge of
approximately $202.1 million was recorded for the year ended December 31,
2004.
General
and Administrative.
General
and administrative costs were $19.4 million in 2004. General and administrative
costs are comprised of items such as salaries and employee benefits, legal
fees,
contract fees and the corporate overhead allocation. In addition, General
and administrative costs include stock-based compensation. On January 1,
2003, the Predecessor adopted the fair market value method of accounting for
stock-based compensation pursuant to SFAS No. 123. Stock compensation
expense of $0.8 million was recorded in 2004.
Total
Other expense
Other
expense for the year ended December 31, 2006 (Successor) was $12.9 million
and
is primarily comprised of interest expense of $17.4 million (net of $2.1 million
of capitalized interest) offset by interest income of $4.5 million. The interest
expense is associated with the senior secured revolving line of credit and
second lien term loan and the interest income is related to the interest earned
on the overnight investments of our cash balances.
Other
expense for the six months ended December 31, 2005 (Successor) is primarily
associated with interest expense of $8.2 million, including amortization of
deferred loan fees of $0.6 million related to interest on our senior credit
facility and term loan. Interest income of $1.8 million was earned on available
cash invested in short term money market investments.
For
the
six months ended June 30, 2005, other expense of $7.0 million was associated
with the intercompany debt with Calpine Corporation.
For
the
year ended December 31, 2004, other expense was primarily associated with
interest expense on intercompany debt with Calpine Corporation. The intercompany
debt balances at December 31, 2004 were $127.2 million. Interest rates on
affiliated party debt ranged from 8.75% to 9.05% in 2004. Capitalized interest
was $0.7 million in 2004.
Provision
for Income Taxes
For
the
year ended December 31, 2006 and six months ended December 31, 2005 (Successor),
the effective tax rate was 38.3% and 39.7%, respectively. For the six months
ended June 30, 2005 and year ended December 31, 2004 (Predecessor), the
effective tax rate was 38.1% for both periods. The provision for income taxes
differs from the taxes computed at the federal statutory income tax rate due
primarily to state taxes.
Liquidity
and Capital Resources
Our
primary source of capital and liquidity is our operating cash flow. We also
maintain a revolving line of credit which can be assessed as needed to
supplement operating cash flow. In addition, concurrent with the Acquisition,
BNP Paribas provided us with a second lien term loan.
Operating
cash flow. Our
cash
flows depend on many factors, including the price of oil and natural gas and
the
success of our development and exploration activities as well as future
acquisitions. We actively manage our exposure to commodity price fluctuations
by
executing derivative transactions to hedge the change in prices of our
production thereby mitigating our exposure to price declines, but these
transactions will also limit our earnings potential in periods of rising natural
gas prices. This derivative transaction activity will allow us the flexibility
to continue to execute our capital plan if prices decline during the period
our
derivative transactions are in place. In addition, the majority of our capital
expenditures will be discretionary and could be curtailed if our cash flows
decline from expected levels.
Senior Secured
Revolving Line of Credit. BNP
Paribas, in July 2005 provided us with a senior secured revolving line of
credit concurrent with the Acquisition in the amount of up to $400.0 million
(“Revolver”). This Revolver was syndicated to a group of lenders on
September 27, 2005. Availability under the Revolver is restricted to the
borrowing base, which initially was $275.0 million and was reset to $325.0
million, upon amendment, as a result of the hedges put in place in
July 2005 and the favorable effects of the exercise of the over-allotment
option we granted in our private equity offering in July 2005 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% (6.85% at December 31, 2006). Such margins will
fluctuate based on the utilization of the facility. Borrowings under the
Revolver are collateralized by perfected first priority liens and security
interests on substantially all of our assets, including a mortgage lien on
oil
and natural gas properties having at least 80% of the SEC PV-10 pretax reserve
value, a guaranty by all of our domestic subsidiaries, a pledge of 100% of
the
stock of domestic subsidiaries and a lien on cash securing the Calpine gas
purchase and sale contract. These collateralized amounts under the mortgages
are
subject to semi-annual reviews based on updated reserve information. We are
subject to the financial covenants of a minimum current ratio of not less than
1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio
of
not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for
the four fiscal quarters then ended, measured quarterly with the pro forma
effect of acquisitions and divestitures. At December 31, 2006, our current
ratio
was 2.7 to 1.0, as adjusted per current agreements and our leverage ratio was
1.2 to 1.0. In addition, we are subject to covenants limiting dividends and
other restricted payments, transactions with affiliates, incurrence of debt,
changes of control, asset sales, and liens on properties. We were in compliance
with all covenants at December 31, 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 December 31, 2006.
Second
Lien Term Loan.
In July 2005, BNP Paribas provided us with a second lien term loan in the
amount of $100.0 million (“Term Loan”). On September 27, 2005, we repaid
$25.0 million of borrowings on the Term Loan, reducing the balance to $75.0
million and syndicated the Term Loan to a group of lenders including BNP
Paribas. Borrowings under the Term Loan initially bore interest at LIBOR plus
5.00%. As a result of the hedges put in place in July 2005 and the favorable
effects of our private equity placement, as described above, the interest rate
for the Term Loan has been reduced to LIBOR plus 4.00% (9.35% at December 31,
2006). The Term Loan is collateralized by second priority liens on substantially
all of our assets. We are subject to the financial covenants of a minimum asset
coverage ratio of not less than 1.5 to 1.0 and a maximum leverage ratio of
not
more than 4.0 to 1.0, calculated at the end of each fiscal quarter for the
four
fiscal quarters then ended, measured quarterly with the pro forma effect of
acquisitions and divestitures. In addition, we are subject to covenants limiting
dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales, and liens on properties.
We
were in compliance with all covenants at December 31, 2006. The revised
principal balance of the Term Loan is due and payable on July 7,
2010.
Working
Capital
At
December 31, 2006, we had a working capital surplus of $30.7 million. Our
working capital is affected primarily by fluctuations in the fair value of
our
commodity derivative instruments, deferred taxes associated with hedging
activities, cash and cash equivalents balance and our capital spending program.
As of December 31, 2006, the working capital asset balances of our cash and
cash
equivalents and derivative instruments were approximately $62.8 million and
$20.5 million, respectively, and there was no balance for current deferred
tax
assets. In addition, the associated working capital liability balances for
accrued liabilities and deferred tax liabilities were approximately $43.1
million and $7.7 million, respectively, as of December 31, 2006.
Cash
Flows
|
Successor-Consolidated
|
Predecessor-Combined
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended
December
31,
2005
|
Six
Months Ended
June
30,
2005
|
Year
Ended
December
31,
2004
|
||||||||||||
|
(In
thousands)
|
|||||||||||||||
|
Cash
flows provided by operating activities
|
$
|
199,610
|
$
|
63,744
|
$
|
59,379
|
$
|
125,600
|
|||||||
|
Cash
flows (used in) provided by investing activities
|
(236,064
|
)
|
(943,246
|
)
|
(30,645
|
)
|
164,433
|
||||||||
|
Cash
flows (used in) provided by financing activities
|
(490
|
)
|
979,226
|
(27,239
|
)
|
(290,334
|
)
|
||||||||
|
Net
(decrease) increase in cash and cash equivalents
|
$
|
(36,944
|
)
|
$
|
99,724
|
$
|
1,495
|
$
|
(301
|
)
|
|||||
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 expenses and administrative
expenses.
Net
cash
provided by operating activities is largely affected by our net income,
excluding non-cash expenses such as depreciation, depletion, and amortization
and deferred income tax. For the year ended December 31, 2006 (Successor),
our
net income was $44.6 million with total production of 33.4 Bcfe. Natural gas
prices averaged $7.81 per Mcf, including the effects of hedging, and oil
averaged $64.01 per Bbl.
Net
cash
provided by operating activities for the six months ended December 31, 2005
(Successor) was $63.7 million generated from total production of 13.5 Bcfe
with
revenue of $113.1 and net income of $17.5 million. Natural gas prices averaged
$8.23 per Mcf, including the effects of hedging, and oil averaged $59.52 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.
Net
cash
provided by operating activities for the year ended December 31, 2004 were
$125.6 million generated from total production of 40.9 Bcfe with revenue of
$248.0 million.
Investing
Activities.
The
primary driver of cash used in investing activities is capital
spending.
Cash
used
in investing activities for the year ended December 31, 2006 was $236.1 million
and related to our expenditures for the acquisition, drilling and development
of
oil and gas properties. These expenditures were primarily from the California,
South Texas and Gulf of Mexico regions and included acquisitions of $35.3
million.
Cash
used
in investing activities for the six months ended December 31, 2005 was
$943.2 million primarily relating to the Acquisition in the net cash amount
of
$910 million (excluding fees, purchase price adjustments and expenses) and
$32
million in capital expenditures spent after the acquisition.
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.
Cash provided
by investing activities for the year ended December 31, 2004 was $164.4
million primarily related to the completed sale of Calpine’s Rocky Mountain
natural gas properties that were primarily concentrated in the two geographic
areas of the Colorado Piceance Basin and the New Mexico San Juan Basin. As
a
result of the sale, Calpine recorded income from discontinued operations, net
of
tax of $68.4 million.
Financing
Activities.
The
primary driver of cash used in financing activities is equity transactions
and
issuance and repayments of debt.
Net
cash
used in financing activities for the year ended December 31, 2006 is primarily
associated with the purchases of treasury stock surrendered by the employees
to
pay tax withholding upon the vesting of restricted stock awards offset by
proceeds from issuances of common stock.
Net
cash
provided by financing activities for the six months ended December 31, 2005
was $979.2 million. This was due to receipt of $800 million in equity offering
proceeds net of $55.6 million in transaction fees and borrowings on our $325
million senior credit facility subsequently used for the acquisition of the
oil
and natural gas properties of Calpine, operating needs, the 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.
Net
cash
used in financing activities for the year ended December 31, 2004 was primarily
due to the cash used in discontinued operations of approximately $218.7 million,
resulting from asset sales.
Commodity
Prices and Related Hedging Activities
The
energy markets have historically been very volatile and there can be no
assurance that oil and natural gas prices will not be subject to wide
fluctuations in the future. To mitigate our exposure to changes in commodity
prices, management has adopted a policy of hedging oil and natural gas prices
from time to time primarily through the use of certain derivative instruments
including fixed price swaps, costless collars, and put options. Although not
risk free, we believe this policy will reduce our exposure to commodity price
fluctuations and thereby achieve a more predictable cash flow. Consistent with
this policy, we have entered into a series of natural gas fixed-price swaps,
which are intended to establish a fixed price for a significant portion of
our
expected natural gas production through 2009. The fixed-price swap agreements
we
have entered into require payments to (or receipts from) counterparties based
on
the differential between a fixed price and a variable price for a notional
quantity of natural gas without the exchange of underlying volumes. The notional
amounts of these financial instruments were based on expected proved production
from existing wells at inception of the hedge instruments.
Consistent
with our hedge policy, we have also entered into costless collar transactions,
which are intended to establish a floor price and ceiling price for a portion
of
our expected production in 2007. If the floating price each month at the
settlement point is greater than the ceiling price, we pay the counterparty
an
amount equal to the positive difference between the floating price and the
ceiling price multiplied by the notional volume for the contract month. If
the
floating price for each month is less than the floor price, the counterparty
pays us an amount equal to the positive difference between the floating price
and the floor price multiplied by the notional volume for the contract month.
See “Item 7A. Quantitative and Qualitative Disclosure About Market
Risk”.
In
accordance with SFAS No. 133, as amended, all derivative instruments, not
designated as a normal purchase sale, are recorded on the balance sheet at
fair
market value and changes in the fair market value of the derivatives are
recorded each period in current earnings or other comprehensive income,
depending on whether a derivative is designated as a hedge transaction, and
depending on the type of hedge transaction. Our derivative contracts are cash
flow hedge transactions in which we are hedging the variability of cash flow
related to a forecasted transaction. Changes in the fair market value of these
derivative instruments are reported in other comprehensive income and
reclassified as earnings in the period(s) in which earnings are impacted by
the
variability of the cash flow of the hedged item. We assess the effectiveness
of
hedging transactions on a quarterly basis, consistent with documented risk
management strategy for the particular hedging relationship. Changes in the
fair
market value of the ineffective portion of cash flow hedges, if any, are
included in other income (expense).
Our
current hedge positions are with counterparties that are lenders in our credit
facilities. This allows us to securitize any margin obligation resulting from
a
negative change in the fair market value of the derivative contracts in
connection with our credit obligations and eliminate the need for independent
collateral postings. As of December 31, 2006, we had no deposits for
collateral.
The
following table sets forth the results of third party hedging transactions
settled for the year ended December 31, 2006:
|
For
the
Year
Ended
December
31, 2006
|
For
the
Six
Months Ended
December
31, 2005
|
||||||
|
Natural
Gas
|
|||||||
|
Quantity
settled (MMBtu)
|
20,075,000
|
7,956,000
|
|||||
|
Increase
(Decrease) in natural gas sales revenue (In thousands)
|
$
|
29,578
|
(16,576
|
)
|
|||
Interest
Rate Risks
Borrowings
under our Revolver and Term Loan mature on July 7, 2009 and July 7, 2010,
respectively, and bear interest at a LIBOR-based rate. This exposes us to risk
of earnings loss due to changes in market rates. Although we continue to
evaluate the risks related to this exposure, we have not entered into any
interest rate swap agreements to mitigate such risk as of December 31,
2006. If we determine the risk may become substantial and the costs are not
prohibitive, we may enter into interest rate swap agreements in the
future.
Capital
Requirements
The
historical capital expenditures summary table is included in Item 1. Business
and is incorporated herein by reference.
Our
capital expenditures for the year ended December 31, 2006 were $240.6 million
and we currently expect to expend approximately $250.0 million during 2007.
We
believe we have adequate expected cash flows from operations and available
borrowings under our revolving credit facility to fund our budgeted capital
expenditures.
Commitments
and Contingencies
As
is
common within the industry, we have entered into various commitments and
operating agreements related to the exploration and development of and
production from proved oil and natural gas properties. It
is
management’s belief that such commitments will be met without a material adverse
effect on our financial position, results of operations or cash
flows.
Contractual
Obligations.
At
December 31, 2006, the aggregate amounts of our contractually obligated
payment commitments for the next five years are as follows:
|
Payments
Due By Period
|
||||||||||||||||
|
Total
|
2007
|
2008
to 2009
|
2010
to 2011
|
2012
& Beyond
|
||||||||||||
|
(In
thousands)
|
||||||||||||||||
|
Senior
secured revolving line of credit
|
$
|
165,000
|
$
|
-
|
$
|
165,000
|
$
|
-
|
$
|
-
|
||||||
|
Second
lien term loan
|
75,000
|
-
|
-
|
75,000
|
-
|
|||||||||||
|
Operating
leases
|
14,380
|
2,421
|
4,199
|
3,782
|
3,978
|
|||||||||||
|
Interest
payments on long-term debt (1)
|
53,076
|
18,315
|
31,149
|
3,612
|
-
|
|||||||||||
|
Rig
commitments
|
14,895
|
14,895
|
-
|
-
|
-
|
|||||||||||
|
Total
contractual obligations
|
$
|
322,351
|
$
|
35,631
|
$
|
200,348
|
$
|
82,394
|
$
|
3,978
|
||||||
|
(1)
|
Future
interest payments were calculated based on interest rates and
amounts outstanding at December 31,
2006.
|
Asset
retirement Obligation.
The
Company also has liabilities of $10.7 million related to asset retirement
obligations on its Consolidated Balance Sheet at December 31, 2006 excluded
from the table above. Due to the nature of these obligations, we cannot
determine precisely when the payments will be made to settle these obligations.
See Note 9 of the Consolidated/Combined Financial Statements.
Purchase and
Sale Agreement with Calpine.
Under
the Purchase Agreement, Calpine agreed to transfer to us certain properties.
At
the closing of the Acquisition in July 2005, 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, which
the parties believed at the time were required, in order to effect transfer
of
legal 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 legal title for
these remaining properties, except those subject to properly executed
preferential rights to purchase. The SEC PV-10 pretax value of these properties
at December 31, 2005 was approximately $72.4 million. Based on our internal
calculations, we estimate the SEC PV-10 pretax value of these properties at
current market prices at December 31, 2006 to be approximately $53.0 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 legal title,
free of any encumbrances, 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 and Calpine’s performance of its
obligations under the “further assurances” provisions of the Purchase Agreement.
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.
Contingencies
We
are
party to various litigation matters arising out of the normal course of
business. Although 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 operation or cash flows.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the Bankruptcy Court on December 20, 2005. Calpine
Energy Services, L.P., which filed for bankruptcy, has continued to make the
required deposits into 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 (“MSA”) with the Company. The MSA was entered into by the
Company and Calpine in July 2005 for the period through June 30,
2007.
The
filing raises certain concerns regarding aspects of our relationship with
Calpine which we will closely monitor as the Calpine bankruptcy proceeds. See
further discussion of our concerns under Item 1A. Risk Factors.
Transfers
of Legal Title 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
at the time of the Acquisition as requiring third party consents or waivers
of
preferential rights to purchase that were not received before closing. Legal
title for those Non-Consent Properties was not 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 legal 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 us for approximately $0.3 million for a property which was transferred
to
us but will be transferred to the appropriate third party should it properly
exercise its preferential purchase right and upon Calpine’s performance of its
remaining 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 for which a third party’s
preferential right to purchase was properly exercised) 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 legal
title and that such properties are not part of Calpine’s bankruptcy estate. Upon
our receipt from Calpine of record legal title, free of any mortgages or other
liens, to these Non-Consent Properties and Calpine’s performance or its 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 and
performance of Calpine’s obligations under the “further assurances” provisions
of the Purchase and Sale Agreement.
Our
statement of operations for the year ended December 31, 2006 and six months
ended December 31, 2005 does not include any net revenues or production from
any
of the Non-Consent Properties, or those properties subject to preferential
rights.
If
Calpine does not provide us with record legal 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 validly exercised
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 should that third party properly exercise their
preferential rights.
In
addition, as to certain of the other oil and natural gas properties we purchased
from Calpine in the Acquisition and for which payment was made on July 7, 2005,
we will seek additional documentation from Calpine to eliminate any open issues
in our title or resolve any issues as to the clarity of our ownership. Requests
for additional documentation are customary in connection with transactions
similar to the Acquisition. In the Acquisition, certain of these properties
require ministerial governmental action approving us as qualified assignee
and
operator, which is typically required even though in most cases Calpine has
already conveyed the properties to us free and clear of mortgages and liens
by
Calpine’s creditors. As to certain other properties, the documentation delivered
by Calpine at closing under the Purchase Agreement was incomplete. We remain
hopeful that Calpine will work cooperatively with us to secure these ministerial
governmental approvals and to accomplish the curative corrections for all of
these properties. In addition, as to all properties acquired by us in the
Acquisition, Calpine contractually agreed to provide us with such further
assurances as we may reasonably request. Nevertheless, as a result of Calpine’s
bankruptcy filing, it remains uncertain as to whether Calpine will respond
cooperatively. If Calpine does not fulfill its contractual obligations and
does
not complete the documentation necessary to resolve these issues, we will pursue
all available remedies, including but not limited to a declaratory judgment
to
enforce our rights and actions to quiet title. After pursuing these matters,
if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome our
management considers to be remote, then we could experience losses which could
have a material adverse effect on our financial condition, statement of
operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases 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 it in order to avoid the automatic
forfeiture of any interest it may have in these leases by operation of a
statutory deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to us or Calpine, but we understand
it
was meant to allow Calpine to preserve and avoid forfeiture under the Bankruptcy
Code of whatever interest Calpine may possess, if any, in these oil and natural
gas leases. We dispute Calpine’s contention that it may have an interest in any
significant portion of these oil and natural gas leases and intend to take
the
necessary steps to protect all of our rights and interest in and to the leases.
On July 7, 2006, we filed an objection in response to Calpine’s motion, wherein
we asserted that oil and natural gas leases constitute interests in real
property that are not subject to “assumption” under the Bankruptcy Code. In the
objection we also requested that (a) the Bankruptcy Court eliminate from the
order certain Federal offshore leases from the Calpine motion because these
properties were fully conveyed to us in July 2005, and the Minerals Management
Service has subsequently recognized us as owner and operator of all but three
of
these properties, and (b) any order entered by the Bankruptcy Court be without
prejudice to, and fully preserve our rights, claims and legal arguments
regarding the characterization and ultimate disposition of the remaining
described oil and natural gas properties. In our objection, we also urged the
Bankruptcy Court to require the parties to promptly address and resolve any
remaining issues under the pre-bankruptcy definitive agreements with Calpine
and
proposed to the Bankruptcy Court that the parties seek arbitration (or at least
mediation) to complete the following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we have already
paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay Calpine, which we have concluded
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 Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render our objection
inapplicable at that time; and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and us to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent Properties.
|
On
August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts as well as unliquidated damages in amounts that
can not presently be determined. We
continue to work with Calpine on a cooperative and expedited basis toward
resolution of unresolved conveyance of properties and post-closing adjustments
under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases, these
parties have further extended this deadline time by stipulation. The deadline
was first extended to January 31, 2007 and recently was further extended to
April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007
with respect to the CSLC Leases. The Bankruptcy Court entered Orders related
to
the MMS Oil and Gas Leases and CSLC Leases which included appropriate language
that we negotiated with Calpine for our protection in this regard.
Recently,
Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy
Court for the period in which only Calpine, exclusively, may file its plan
of
reorganization. While there is no assurance that Calpine will file a plan of
reorganization by the deadline, or that such a plan will be approved by the
creditors and the Bankruptcy Court, we remain optimistic that the issues
involving conclusion of the remaining conveyances of the Non-Consent Properties
and obtaining the further assurances from Calpine under the Purchase Agreement,
including perhaps resolution of any and all claims, may occur during
2007.
Calpine
recently requested Bankruptcy Court approval of a new credit facility which
would require it to grant liens to these new lenders in all of its assets,
including any interest it may still hold in any oil and gas properties it
obligated itself to convey to us under the Purchase Agreement. The Bankruptcy
Court entered into an Order approving Calpine’s ability to obtain this new loan
which includes appropriate language that we negotiated with Calpine for our
protection in this regard.
However,
there can be no assurance that Calpine, its creditors or other interest holders
will not challenge the fairness of the Acquisition. For a number of reasons,
including our understanding of the process that Calpine followed in allowing
market forces to set the purchase price for the Acquisition, we continue to
believe that it is unlikely that any challenges by the Calpine debtors or their
creditors to the overall fairness of the Acquisition would be successful. We
will take all necessary action to ensure our rights under the Purchase
Agreement, the MMS Oil and Gas Leases, the CSLC Leases and the Bankruptcy Code
are fully protected.
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 December 31, 2006 and 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
We
have
made preliminary preparations in connection with our participation 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. We have been selected by the DOE
for
this project. Under WESTCARB, we 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. Our maximum contribution to WESTCARB is
$1.0
million and will be limited to 20% of the total contributions to the project.
We
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 December 31, 2006 as the
study
is still in the preliminary stage.
Off-Balance
Sheet Arrangements
At
December 31, 2006 and 2005, we did not have any off-balance sheet
arrangements.
Forward-Looking
Statements
This
report includes various “forward-looking statements” within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the
Securities Exchange Act of 1934, as amended. All
statements other than statements of historical fact included or incorporated
by
reference in this report are forward-looking statements, including without
limitation all statements regarding future plans, business objectives,
strategies, expected future financial position or performance, expected future
operational position or performance, budgets and projected costs, future
competitive position, or goals and/or projections of management for future
operations. In
some
cases, you can identify a forward-looking statement by terminology such as
“may”, “will”, “could”, “should”, “expect”, “plan”, “project”, “intend”,
“anticipate”, “believe”, “estimate”, “predict”, “potential”, “pursue”, “target”
or “continue”, the negative of such terms or variations thereon, or other
comparable terminology.
The
forward-looking statements contained in this report are largely based on our
expectations for the future, which reflect certain estimates and assumptions
made by our management. These estimates and assumptions reflect our best
judgment based on currently known market conditions, operating trends, and
other
factors. Although we believe such estimates and assumptions to be reasonable,
they are inherently uncertain and involve a number of risks and uncertainties
that are beyond our control. As such, management’s assumptions about future
events may prove to be inaccurate. For a more detailed description of the risks
and uncertainties involved, see Item 1A. Risk Factors in this report. We do
not
intend to publicly update or revise any forward-looking statements as a result
of new information, future events, changes in circumstances, or otherwise.
These
cautionary statements qualify all forward-looking statements attributable to
us,
or persons acting on our behalf. Management cautions all readers that the
forward-looking statements contained in this report are not guarantees of future
performance, and we cannot assure any reader that such statements will be
realized or that the events and circumstances they describe will occur. Factors
that could cause actual results to differ materially from those anticipated
or
implied in the forward-looking statements herein include, but are not limited
to:
|
·
|
The
supply and demand for oil, natural gas, and other products and
services;
|
|
·
|
The
price of oil, natural gas, and other products and services;
|
|
·
|
Conditions
in the energy markets;
|
|
·
|
Changes
or advances in technology;
|
|
·
|
Reserve
levels;
|
|
·
|
Currency
exchange rates and inflation;
|
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
|
·
|
Commodity
prices;
|
|
·
|
Future
processing volumes and pipeline throughput;
|
|
·
|
Conditions
in the securities and/or capital markets;
|
|
·
|
The
occurrence of property acquisitions or
divestitures;
|
|
·
|
Drilling
and exploration risks;
|
|
·
|
The
availability and cost of processing and transportation;
|
|
·
|
Developments
in oil-producing and natural gas-producing countries;
|
|
·
|
Competition
in the oil and natural gas
industry;
|
|
·
|
The
ability and willingness of our current or potential counterparties
or
vendors to enter into transactions with us and/or to fulfill their
obligations to us;
|
|
·
|
Our
ability to access the capital markets on favorable terms or at
all;
|
|
·
|
Our
ability to obtain credit and/or capital in desired amounts and/or
on
favorable terms;
|
|
·
|
Present
and possible future claims, litigation and enforcement actions;
|
|
·
|
Effects
of the application of applicable laws and regulations, including
changes
in such regulations or the interpretation thereof;
|
|
·
|
Relevant
legislative or regulatory changes, including retroactive royalty
or
production tax regimes, changes in environmental regulation, environmental
risks and liability under federal, state and foreign environmental
laws
and regulations;
|
|
·
|
General
economic conditions, either internationally, nationally or in
jurisdictions affecting our business;
|
|
·
|
The
amount of resources expended in connection with Calpine’s bankruptcy,
including costs for lawyers, consultant experts and related expenses,
as
well as all lost opportunity costs associated with our internal resources
dedicated to these matters;
|
|
·
|
Disputes
with mineral lease and royalty owners regarding calculation and payment
of
royalties;
|
|
·
|
The
weather, including the occurrence of any adverse weather conditions
and/or
natural disasters affecting our business;
and
|
|
·
|
Any
other factors that impact or could impact the exploration of oil
or
natural gas resources, including but not limited to the geology of
a
resource, the total amount and costs to develop recoverable reserves,
and
legal title, regulatory, natural gas administration, marketing and
operational factors relating to the extraction of oil and natural
gas.
|
Item
7A. Quantitative and Qualitative Disclosures About Market
Risk
The
primary objective of the following information is to provide forward-looking
quantitative and qualitative information about our potential exposure to market
risks. The term “market risk” refers to the risk of loss arising from adverse
changes in oil and natural gas prices and interest rates. The disclosures are
not meant to be precise indicators of expected future losses, but rather
indicators of reasonable possible losses. This forward-looking information
provides indicators of how we view and manage our ongoing market risk exposures.
All of our market risk sensitive instruments were entered into for purposes
other than speculative trading.
Commodity
Price Risk.
Our
major market risk exposure is in the pricing of our oil and natural gas
production. Realized pricing is primarily driven by the prevailing worldwide
price for crude oil and spot market prices applicable to our U.S. natural gas
production. Pricing for oil and natural gas production has been volatile and
unpredictable for several years, and we expect this volatility to continue
in
the future. The prices we receive for production depend on many factors outside
of our control. Based on average daily production for the year ended December
31, 2006, our annual income before income taxes would change by approximately
$3.0 million for each $0.10 per Mcfe change in natural gas prices and
approximately $0.6 million for each $1.00 per Bbl change in crude oil prices.
We
use
derivative transactions to manage exposure to commodity prices. Our objectives
for holding derivative instruments are to achieve a consistent level of cash
flow to support a portion of our planned capital spending. Our use of derivative
transactions for hedging activities could materially affect our results of
operations, in particular quarterly or annual periods since such instruments
can
limit our ability to benefit from favorable price movements. We do not enter
into derivative instruments for speculative purposes.
We
believe the use of derivative transactions, although not free of risk, allows
us
to reduce our exposure to oil and natural gas sales price fluctuations and
thereby achieve a more predictable cash flow. While the use of derivative
instruments limits the downside risk of adverse price movements, their use
may
also limit future revenues from favorable price movements. Moreover, our
derivative contracts generally do not apply to all of our production and thus
provide only partial price protection against declines in commodity prices.
We
expect that the amount of our derivative contracts will vary from time to
time.
Our
fixed-price swap agreements are used to fix the sales price for our anticipated
future oil and natural gas production. Upon settlement, we receive a fixed
price
for the hedged commodity and pay our counterparty a floating market price,
as
defined in each instrument. These instruments are settled monthly. When the
floating price exceeds the fixed price for a contract month, we pay our
counterparty. When the fixed price exceeds the floating price, our counterparty
is required to make a payment to us. We have designated these swaps as cash
flow
hedges.
As
of
December 31, 2006, we had the following financial fixed price swap
positions outstanding with average underlying prices that represent hedged
prices of commodities at various market locations:
|
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)
|
|||||||||||||||
|
2007
|
Swap
|
Cash
flow
|
49,341
|
18,009,500
|
$
|
7.76
|
40%
|
|
$
|
17,216
|
||||||||||||
|
2008
|
Swap
|
Cash
flow
|
49,909
|
18,266,616
|
7.62
|
44%
|
|
(4,440
|
)
|
|||||||||||||
|
2009
|
Swap
|
Cash
flow
|
26,141
|
9,541,465
|
6.99
|
26%
|
|
(5,962
|
)
|
|||||||||||||
|
45,817,581
|
$
|
6,814
|
||||||||||||||||||||
|
(1)
|
Estimated
based on net gas reserves presented in the December 31, 2006 Netherland,
Sewell & Associates, Inc. reserve
report.
|
We
have
also entered into costless collar transactions, which are intended to establish
a floor price and ceiling price for a portion of our expected production in
2007. If the floating price each month at the settlement point is greater than
the ceiling price, we pay the counterparty an amount equal to the positive
difference between the floating price and the ceiling price multiplied by the
notional volume for the contract month. If the floating price for each month
is
less than the floor price, the counterparty pays us an amount equal to the
positive difference between the floating price and the floor price multiplied
by
the notional volume for the contract month.
The
following table describes our open costless collar transactions at
December 31, 2006 by associated notional volumes and contracted ceiling and
floor price at various market locations:
|
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)
|
|||||||||||||||
|
2007
|
Costless
Collar
|
Cash
flow
|
10,000
|
3,650,000
|
$
|
7.19
|
$
|
10.03
|
$
|
3,322
|
||||||||||||
|
3,650,000
|
$
|
3,322
|
||||||||||||||||||||
The
total
of proved natural gas production hedged in 2006 for the costless collars is
approximately 8% based on the December 31, 2006 reserve report prepared by
Netherland, Sewell & Associates, Inc.
Interest
Rate Risks.
In July
2005, we entered into our credit facilities including (1) a senior secured
revolving line of credit in the aggregate amount of up to $400 million (the
“Revolver”), and (2) a senior secured second lien term loan, initially, in
the aggregate amount of $100 million (the “Term Loan”). Both the Revolver and
the Term Loan were amended and syndicated on September 27,
2005.
Availability
under the Revolver is restricted to a borrowing base calculation of value
assigned to proved oil and natural gas reserves. The initial borrowing base
was
$275 million and was reset to $325 million as of the syndication date as a
result of the derivative transactions and the favorable effects of our
underwriters exercising the over-allotment option we granted in connection
with
our sale of 45,312,500 shares of our common stock, through which we received
$70
million of funds (net of transaction fees), which were used to repay $60.0
million of borrowings under the Revolver in July 2005 and the remainder for
unspecified operating costs of our oil and natural gas properties and general
and administrative costs from our oil and natural gas operations. The borrowing
base is subject to review and adjustment on a semi-annual basis and other
interim adjustments, including adjustments based on our derivative arrangements.
Amounts outstanding under the Revolver bear interest at specified margins over
the London Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00%, based on facility
utilization. The Revolver will mature on July 7, 2009.
The
Term
Loan initially in the amount of $100 million was reduced to $75 million on
the
syndication date of September 27, 2005. Borrowings under the Term Loan
initially bore interest at LIBOR plus 5.00%. In September 2005, $25 million
of
borrowings under the Term Loan were repaid. As a result of the derivative
transactions and the favorable effect 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 Term Loan is collateralized by a second lien
on
all assets securing the Revolver. The Term Loan will mature on July 7,
2010.
We
had
availability under the facility of $159.0 million as of December 31, 2006.
A one hundred basis point increase in each of the LIBOR rate and federal funds
rate as of December 31, 2006 and 2005 for both our revolver of credit and term
debt would result in an estimated $2.4 million increase, respectively, in annual
interest expense.
Item
8. Financial Statements and Supplementary
Data
Index
to Financial Statements
|
Page
|
|
|
Report
of Independent Registered Public Accounting Firm
|
50
|
|
Report
of Independent Registered Public Accounting Firm
|
51
|
|
Consolidated
Balance Sheet at December 31, 2006 and 2005
|
52
|
|
|
|
|
Consolidated/Combined
Statement of Operations for the year ended December 31, 2006 (Successor),
for the six months ended December 31, 2005 (Successor), for the
six months
ended June 30, 2005 (Predecessor) and for the year ended December
31, 2004
(Predecessor)
|
53
|
|
Consolidated/Combined
Statement of Cash Flows for the year ended December 31, 2006 (Successor),
for the six months ended December 31, 2005 (Successor), for the
six months
ended June 30, 2005 (Predecessor) and for the year ended December
31, 2004
(Predecessor)
|
54
|
|
Consolidated/Combined
Statement of Stockholders' Equity and Owner's Net Investment for
the year
ended December 31, 2006 (Successor), for the six months ended
December 31, 2005 (Successor), for the six months ended June 30,
2005
(Predecessor) and for the year ended December 31, 2004
(Predecessor)
|
56
|
|
Notes
to Consolidated/Combined Financial Statements
|
57
|
Report
of Independent Registered Public Accounting Firm
To
the
Board of Directors
and
Stockholders of Rosetta Resources Inc.:
In
our
opinion, the consolidated
balance sheets as of December 31, 2006 and 2005 and the related consolidated
statements of operations, of cash flows and of changes in stockholders' equity
and comprehensive income for the year ended December 31, 2006 and the six months
ended December 31, 2005 present fairly, in all material respects, the
consolidated financial position of Rosetta Resources Inc. and its subsidiaries
(successor, the "Company") at December 31, 2006 and 2005 and the results of
their operations and their cash flows for the year ended December 31, 2006
and
the six months ended December 31, 2005 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of
the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As
described in Note 3 to the consolidated financial statements, the Company
changed its method of accounting for stock-based compensation effective January
1, 2006.
As
described
in Note 11 to the consolidated financial statements, the Company's former parent
filed bankruptcy subsequent to the Company's acquisition of the oil and natural
gas business of Calpine Corporation and Affiliates.
/s/
PricewaterhouseCoopers LLP
March
15,
2007
Houston,
Texas
Report
of Independent Registered Public Accounting Firm
To
the
Board of Directors
and
Stockholders of Rosetta Resources Inc.:
In
our
opinion, the
combined statements of operations, of cash flows and of changes in owner's
net
investment for the six months ended June 30, 2005 and the year ended December
31, 2004 present fairly, in all material respects, the results of operations
and
cash flows of the Domestic Oil & Natural Gas Properties of Calpine
Corporation and Affiliates (predecessor) for the six months ended June 30,
2005
and the year ended December 31, 2004 in conformity with accounting principles
generally accepted in the United States of America. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits. We
conducted our audits of these statements in accordance with the standards of
the
Public Company Accounting Oversight Board (United States). Those standards
require that we plan and perform the audit to obtain reasonable assurance about
whether the financial statements are free of material misstatement. An audit
includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles
used and significant estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
As
described
in Note 17 to the combined financial statements, the Company has significant
transactions and relationships with related parties. Because of these
relationships, it is possible that the terms of these transactions are not
the
same as those that would result from transactions among wholly unrelated
parties.
/s/
PricewaterhouseCoopers LLP
April
19,
2006
Houston,
Texas
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
|
December
31,
2006
|
December
31,
2005
|
||||||
|
Assets
|
|||||||
|
Current
assets:
|
|||||||
|
Cash
and cash equivalents
|
$
|
62,780
|
$
|
99,724
|
|||
|
Accounts
receivable
|
36,408
|
40,051
|
|||||
|
Derivative
instruments
|
20,538
|
1,110
|
|||||
|
Deferred
income taxes
|
-
|
10,962
|
|||||
|
Income
tax receivable
|
-
|
6,000
|
|||||
|
Prepaid
expenses
|
8,761
|
8,511
|
|||||
|
Other
current assets
|
2,965
|
900
|
|||||
|
Total
current assets
|
131,452
|
167,258
|
|||||
|
Oil
and natural gas properties, full cost method, of which $37.8 million
at
December 31, 2006 and $30.6 million at December 31, 2005 were excluded
from amortization
|
1,223,337
|
973,185
|
|||||
|
Other
|
4,562
|
2,912
|
|||||
|
|
1,227,899
|
976,097
|
|||||
|
Accumulated
depreciation, depletion, and amortization
|
(145,289
|
)
|
(40,161
|
)
|
|||
|
Total
property and equipment, net
|
1,082,610
|
935,936
|
|||||
|
Deferred
loan fees
|
3,375
|
4,555
|
|||||
|
Deferred
income taxes
|
-
|
8,594
|
|||||
|
Other
assets
|
1,968
|
2,926
|
|||||
|
Total
other assets
|
5,343
|
16,075
|
|||||
|
Total
assets
|
$
|
1,219,405
|
$
|
1,119,269
|
|||
|
Liabilities
and Stockholders' Equity
|
|||||||
|
Current
liabilities:
|
|||||||
|
Accounts
payable
|
$
|
23,040
|
$
|
13,442
|
|||
|
Accrued
liabilities
|
43,099
|
28,397
|
|||||
|
Royalties
payable
|
9,010
|
15,511
|
|||||
|
Derivative
instruments
|
-
|
29,957
|
|||||
|
Prepayment
on gas sales
|
17,868
|
14,528
|
|||||
|
Deferred
income taxes
|
7,743
|
-
|
|||||
|
Total
current liabilities
|
100,760
|
101,835
|
|||||
|
Long-term
liabilities:
|
|||||||
|
Derivative
instruments
|
11,014
|
52,977
|
|||||
|
Long-term
debt
|
240,000
|
240,000
|
|||||
|
Asset
retirement obligation
|
10,253
|
9,034
|
|||||
|
Deferred
income taxes
|
35,089
|
-
|
|||||
|
Total
liabilities
|
397,116
|
403,846
|
|||||
|
Commitments
and contingencies (Note 11)
|
|||||||
|
Stockholders'
equity:
|
|||||||
|
Common
stock, $0.001 par value; authorized 150,000,000 shares; issued 50,405,794
shares and 50,003,500 shares at December 31, 2006 and December 31,
2005,
respectively
|
50
|
50
|
|||||
|
Additional
paid-in capital
|
755,343
|
748,569
|
|||||
|
Treasury
stock, at cost; 85,788 and no shares at December 31, 2006 and December
31,
2005, respectively
|
(1,562
|
)
|
-
|
||||
|
Accumulated
other comprehensive income (loss)
|
6,315
|
(50,731
|
)
|
||||
|
Retained
earnings
|
62,143
|
17,535
|
|||||
|
Total
stockholders' equity
|
822,289
|
715,423
|
|||||
|
Total
liabilities and stockholders' equity
|
$
|
1,219,405
|
$
|
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)
|
Successor-Consolidated
|
Predecessor
- Combined
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended
December
31,
2005
|
Six
Months Ended
June
30,
2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
Revenues:
|
|||||||||||||||
|
Natural
gas sales
|
$
|
236,496
|
$
|
102,058
|
$
|
13,713
|
$
|
34,348
|
|||||||
|
Oil
sales
|
35,267
|
11,046
|
8,166
|
23,443
|
|||||||||||
|
Oil
and natural gas sales to affiliates
|
-
|
-
|
81,952
|
190,215
|
|||||||||||
|
Total
revenues
|
271,763
|
113,104
|
103,831
|
248,006
|
|||||||||||
|
Operating
Costs and Expenses:
|
|||||||||||||||
|
Lease
operating expense
|
36,273
|
15,674
|
16,629
|
30,785
|
|||||||||||
|
Depreciation,
depletion, and amortization
|
105,886
|
40,500
|
30,679
|
81,590
|
|||||||||||
|
Exploration
expense
|
-
|
-
|
2,355
|
5,352
|
|||||||||||
|
Dry
hole costs
|
-
|
-
|
1,962
|
2,088
|
|||||||||||
|
Impairment
|
-
|
-
|
-
|
202,120
|
|||||||||||
|
Treating
and transportation
|
2,544
|
1,286
|
1,998
|
3,509
|
|||||||||||
|
Affiliated
marketing fees
|
-
|
-
|
913
|
1,887
|
|||||||||||
|
Marketing
fees
|
2,257
|
1,379
|
-
|
-
|
|||||||||||
|
Production
taxes
|
6,433
|
3,975
|
2,755
|
4,322
|
|||||||||||
|
General
and administrative costs
|
33,233
|
14,687
|
9,677
|
19,416
|
|||||||||||
|
Total
operating costs and expenses
|
186,626
|
77,501
|
66,968
|
351,069
|
|||||||||||
|
Operating
income (loss)
|
85,137
|
35,603
|
36,863
|
(103,063
|
)
|
||||||||||
|
Other
(income) expense
|
|||||||||||||||
|
Interest
expense with affiliates, net of interest capitalized
|
-
|
-
|
6,995
|
28,034
|
|||||||||||
|
Interest
expense, net of interest capitalized
|
17,428
|
8,216
|
-
|
-
|
|||||||||||
|
Interest
(income)
|
(4,503
|
)
|
(1,837
|
)
|
(516
|
)
|
(726
|
)
|
|||||||
|
Other
(income) expense, net
|
(40
|
)
|
152
|
207
|
(3,010
|
)
|
|||||||||
|
Total
other expense
|
12,885
|
6,531
|
6,686
|
24,298
|
|||||||||||
|
Income
(loss) before provision for income taxes
|
72,252
|
29,072
|
30,177
|
(127,361
|
)
|
||||||||||
|
Provision
(benefit) for income taxes
|
27,644
|
11,537
|
11,496
|
(48,525
|
)
|
||||||||||
|
Income
(loss) from continuing operations
|
44,608
|
17,535
|
18,681
|
(78,836
|
)
|
||||||||||
|
Income
from discontinued operations, net of tax
|
-
|
-
|
-
|
68,440
|
|||||||||||
|
Net
income (loss)
|
$
|
44,608
|
$
|
17,535
|
$
|
18,681
|
$
|
(10,396
|
)
|
||||||
|
Basic
net income (loss) per share:
|
|||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
0.89
|
$
|
0.35
|
$
|
0.37
|
$
|
(1.58
|
)
|
||||||
|
Income
from discontinued operations
|
-
|
-
|
-
|
1.37
|
|||||||||||
|
Net
income (loss)
|
$
|
0.89
|
$
|
0.35
|
$
|
0.37
|
$
|
(0.21
|
)
|
||||||
|
Diluted
net income (loss) per share:
|
|||||||||||||||
|
Income
(loss) from continuing operations
|
$
|
0.88
|
$
|
0.35
|
$
|
0.37
|
$
|
(1.58
|
)
|
||||||
|
Income
from discontinued operations
|
-
|
-
|
-
|
1.37
|
|||||||||||
|
Net
income (loss)
|
$
|
0.88
|
$
|
0.35
|
$
|
0.37
|
$
|
(0.21
|
)
|
||||||
|
Weighted
average shares outstanding:
|
|||||||||||||||
|
Basic
|
50,237
|
50,003
|
50,000
|
50,000
|
|||||||||||
|
Diluted
|
50,408
|
50,189
|
50,160
|
50,000
|
|||||||||||
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Cash Flows
(In
thousands)
|
Successor-Consolidated
|
Predecessor-Combined
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
Cash
flows from operating activities
|
|||||||||||||||
|
Net
income (loss)
|
$
|
44,608
|
$
|
17,535
|
$
|
18,681
|
$
|
(10,396
|
)
|
||||||
|
Income
(loss) from discontinued operations, net of taxes
|
-
|
-
|
-
|
(68,440
|
)
|
||||||||||
|
Net
income (loss) from continuing operations
|
44,608
|
17,535
|
18,681
|
(78,836
|
)
|
||||||||||
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|||||||||||||||
|
Depreciation,
depletion and amortization
|
105,886
|
40,500
|
30,679
|
81,590
|
|||||||||||
|
Affiliate
interest expense
|
-
|
-
|
(6,995
|
)
|
(28,034
|
)
|
|||||||||
|
Impairment
|
-
|
-
|
-
|
202,120
|
|||||||||||
|
Deferred
income taxes
|
27,472
|
11,537
|
2,874
|
(137,838
|
)
|
||||||||||
|
Amortization
of deferred loan fees recorded as interest expense
|
1,180
|
590
|
-
|
-
|
|||||||||||
|
Income
from unconsolidated investments
|
(171
|
)
|
(241
|
)
|
(161
|
)
|
(324
|
)
|
|||||||
|
Stock
compensation expense
|
5,702
|
4,248
|
-
|
-
|
|||||||||||
|
Other
non-cash charges
|
-
|
-
|
99
|
4,856
|
|||||||||||
|
Change
in operating assets and liabilities:
|
|||||||||||||||
|
Accounts
receivable
|
3,643
|
(40,051
|
)
|
2,378
|
5,486
|
||||||||||
|
Accounts
receivable from affiliates
|
-
|
-
|
6,298
|
(293
|
)
|
||||||||||
|
Income
taxes receivable
|
6,000
|
(6,000
|
)
|
-
|
-
|
||||||||||
|
Other
assets
|
(624
|
)
|
(11,137
|
)
|
2,563
|
(5,267
|
)
|
||||||||
|
Accounts
payable
|
8,765
|
13,442
|
(4,494
|
)
|
1,517
|
||||||||||
|
Accrued
liabilities
|
310
|
3,282
|
241
|
(6,266
|
)
|
||||||||||
|
Royalties
payable
|
(3,161
|
)
|
30,039
|
(1,406
|
)
|
(6,842
|
)
|
||||||||
|
Income
taxes payable
|
-
|
-
|
8,622
|
89,313
|
|||||||||||
|
Cash
provided by continuing operating activities
|
199,610
|
63,744
|
59,379
|
121,182
|
|||||||||||
|
Cash
provided by discontinued operations
|
-
|
-
|
-
|
4,418
|
|||||||||||
|
Net
cash provided by operating activities
|
199,610
|
63,744
|
59,379
|
125,600
|
|||||||||||
|
Cash
flows from investing activities
|
|||||||||||||||
|
Acquisition,
net of cash acquired
|
-
|
(910,064
|
)
|
-
|
-
|
||||||||||
|
Purchases
of property and equipment
|
(236,579
|
)
|
(32,994
|
)
|
(32,202
|
)
|
(68,386
|
)
|
|||||||
|
Disposals
of property and equipment
|
30
|
13
|
1,447
|
14,536
|
|||||||||||
|
Deposits
|
50
|
(201
|
)
|
-
|
-
|
||||||||||
|
Other
|
435
|
-
|
110
|
(83
|
)
|
||||||||||
|
Cash
used in continuing investing activities
|
(236,064
|
)
|
(943,246
|
)
|
(30,645
|
)
|
(53,933
|
)
|
|||||||
|
Cash
provided by discontinued operations
|
-
|
-
|
-
|
218,366
|
|||||||||||
|
Net
cash (used in) provided by investing activities
|
(236,064
|
)
|
(943,246
|
)
|
(30,645
|
)
|
164,433
|
||||||||
(continued)
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Cash Flows (Continued)
(In
thousands)
|
Successor-Consolidated
|
Predecessor-Combined
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
Cash
flows from financing activities
|
|||||||||||||||
|
Equity
offering proceeds
|
-
|
800,000
|
-
|
-
|
|||||||||||
|
Equity
offering transaction fees
|
268
|
(55,629
|
)
|
-
|
-
|
||||||||||
|
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
|
)
|
-
|
-
|
||||||||||
|
Capital
lease
|
-
|
-
|
-
|
(1,420
|
)
|
||||||||||
|
Notes
payable to affiliates
|
-
|
-
|
(27,239
|
)
|
(70,226
|
)
|
|||||||||
|
Proceeds
from issuances of common stock
|
804
|
-
|
-
|
-
|
|||||||||||
|
Purchases
of treasury stock
|
(1,562
|
)
|
-
|
-
|
-
|
||||||||||
|
Cash
(used in) provided by continuing financing activities
|
(490
|
)
|
979,226
|
(27,239
|
)
|
(71,646
|
)
|
||||||||
|
Cash
used in discontinued operations
|
-
|
-
|
-
|
(218,688
|
)
|
||||||||||
|
Net
cash (used in) provided by financing activities
|
(490
|
)
|
979,226
|
(27,239
|
)
|
(290,334
|
)
|
||||||||
|
Net
(decrease) increase in cash
|
(36,944
|
)
|
99,724
|
1,495
|
(301
|
)
|
|||||||||
|
Cash
and cash equivalents, beginning of period
|
99,724
|
-
|
-
|
301
|
|||||||||||
|
Cash
and cash equivalents, end of period
|
$
|
62,780
|
$
|
99,724
|
$
|
1,495
|
$
|
-
|
|||||||
|
Supplemental
disclosures:
|
|||||||||||||||
|
Cash
paid for interest expense, net of capitalized Interest
|
$
|
17,875
|
$
|
(8,057
|
)
|
$
|
-
|
$
|
-
|
||||||
|
Cash
paid for tax
|
$
|
172
|
$
|
6,000
|
$
|
-
|
$
|
-
|
|||||||
|
Supplemental
non-cash disclosures:
|
|||||||||||||||
|
Oil
and gas properties acquired from affiliates in exchange for notes
payable
to affiliates
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
10,100
|
|||||||
|
Capital
expenditures included in accrued liabilities
|
$
|
5,589
|
$
|
33,470
|
$
|
-
|
$
|
-
|
|||||||
|
Accrued
purchase price adjustment
|
$
|
11,400
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||||
The
accompanying notes to the financial statements are an integral part
hereof
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Stockholders’ Equity and Owner’s Net
Investment
(In
thousands, except per share amounts)
|
Common
Stock
|
Additional
|
Accumulated
Other
|
Treasury
Stock
|
Total
Stockholders'
Equity
&
|
|||||||||||||||||||||
|
Predecessor
|
Shares
|
Amount
|
Paid-In
Capital
|
Comprehensive
(Loss)
|
Shares
|
Amount
|
Retained
Earnings
|
Owner's
Net Investment
|
|||||||||||||||||
|
Balance
January 1, 2004
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
-
|
$
|
-
|
$
|
-
|
$
|
233,847
|
|||||||||||
|
Net
Loss
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
(10,396
|
)
|
||||||||||||||||
|
Balance
December 31, 2004
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
223,451
|
|||||||||||||||||
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
18,681
|
|||||||||||||||||
|
Balance
June 30, 2005
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
-
|
$
|
-
|
$
|
-
|
$
|
242,132
|
|||||||||||
|
Successor
|
|||||||||||||||||||||||||
|
Balance
July 1, 2005
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
-
|
$
|
-
|
$
|
-
|
$
|
-
|
|||||||||||
|
Issuance
of common stock, net of offering costs
|
50,003,500
|
50
|
744,321
|
-
|
-
|
-
|
-
|
744,371
|
|||||||||||||||||
|
Vesting
of restricted stock
|
-
|
-
|
4,248
|
-
|
-
|
-
|
-
|
4,248
|
|||||||||||||||||
|
Comprehensive
Income:
|
|||||||||||||||||||||||||
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
-
|
17,535
|
17,535
|
|||||||||||||||||
|
Change
in fair value of derivative hedging instruments
|
-
|
-
|
-
|
(98,400
|
)
|
-
|
-
|
-
|
(98,400
|
)
|
|||||||||||||||
|
Hedge
settlements reclassified to income
|
-
|
-
|
-
|
16,576
|
-
|
-
|
-
|
16,576
|
|||||||||||||||||
|
Tax
(provision)/benefit related to cash flow hedges
|
-
|
-
|
-
|
31,093
|
-
|
-
|
-
|
31,093
|
|||||||||||||||||
|
Comprehensive
Income
|
-
|
-
|
-
|
-
|
-
|
-
|
(33,196
|
)
|
|||||||||||||||||
|
Balance
December 31, 2005
|
50,003,500
|
50
|
748,569
|
(50,731
|
)
|
-
|
-
|
17,535
|
715,423
|
||||||||||||||||
|
Equity
offering - transaction fees
|
-
|
-
|
268
|
-
|
-
|
-
|
-
|
268
|
|||||||||||||||||
|
Stock
issued options
|
49,896
|
-
|
804
|
-
|
-
|
-
|
-
|
804
|
|||||||||||||||||
|
Treasury
stock - employee tax payment
|
-
|
-
|
-
|
85,788
|
(1,562
|
)
|
-
|
(1,562
|
)
|
||||||||||||||||
|
Stock-based
compensation expense
|
-
|
-
|
5,702
|
-
|
-
|
-
|
-
|
5,702
|
|||||||||||||||||
|
Vesting
of restricted stock
|
352,398
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
|||||||||||||||||
|
Comprehensive
Income:
|
|||||||||||||||||||||||||
|
Net
Income
|
-
|
-
|
-
|
-
|
-
|
-
|
44,608
|
44,608
|
|||||||||||||||||
|
Change
in fair value of derivative hedging instruments
|
-
|
-
|
-
|
121,540
|
-
|
-
|
-
|
121,540
|
|||||||||||||||||
|
Hedge
settlements reclassified to income
|
-
|
-
|
-
|
(29,578
|
)
|
-
|
-
|
-
|
(29,578
|
)
|
|||||||||||||||
|
Tax
(provision)/benefit related to cash flow hedges
|
-
|
-
|
-
|
(34,916
|
)
|
-
|
-
|
-
|
(34,916
|
)
|
|||||||||||||||
|
Comprehensive
Income
|
-
|
-
|
-
|
-
|
-
|
-
|
-
|
101,654
|
|||||||||||||||||
|
Balance
December 31, 2006
|
50,405,794
|
$
|
50
|
$
|
755,343
|
$
|
6,315
|
85,788
|
$
|
(1,562
|
)
|
$
|
62,143
|
$
|
822,289
|
||||||||||
The
accompanying notes to the financial statements are an integral part
hereof
Rosetta
Resources Inc.
Notes
to Consolidated/Combined Financial Statements
|
(1)
|
Organization
and Operations of the Company
|
Nature
of Operations. Rosetta
Resources, Inc. (together with its consolidated subsidiaries, the “Company”) was
formed in June 2005 to acquire Calpine Natural Gas L.P. the domestic oil and
natural gas business formerly owned by Calpine Corporation and affiliates
(“Calpine”). The Company (“Successor”) acquired Calpine Natural Gas L.P.
(“Predecessor”) in July 2005 (hereinafter, the “Acquisition”) and together with
all subsequently acquired oil and gas properties is engaged in oil and natural
gas exploration, development, production and acquisition activities in the
United States. The Company’s main operations are primarily concentrated in the
Sacramento Basin of California, the Lobo and Perdido Trends in South Texas,
the
State Waters of Texas, the Gulf of Mexico and the Rocky Mountains.
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, in the Acquisition, the Company acquired substantially all of the
oil
and natural gas business of Calpine and certain of its subsidiaries, excluding
certain non-consent properties described below, for approximately $910 million.
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 the non-consent
properties, which are those properties Calpine believed at the time of the
Acquisition required third party consents or waivers of preferential purchase
rights in order to effect the transfer of record legal title from Calpine to
the
Company or to Calpine entities acquired by the Company in the Acquisition
(“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 has purportedly exercised a preferential right to purchase certain
of the Non-Consent Properties but which we have not been able to verify was
validly exercised. 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 legal title to substantially
all of the remaining Non-Consent Properties will occur. Upon conveyance of
the
legal title of the remaining Non-Consent Properties and Calpine’s performance of
its “further assurances” under the Purchase Agreement, approximately $68
million, the balance of the 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 year ended December 31, 2006 and for the six
months ended December 31, 2005. If the assignment of legal title 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
|
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 if Calpine
provides 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 December 31,
2006.
The
unaudited pro forma information below for the years ended December 31, 2005
and 2004 assume the acquisition of Calpine’s domestic oil and natural gas
business and the related financings occurred at the beginning of the periods
presented. 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.
|
Year
Ended December 31,
|
|||||||
|
2005
|
2004
|
||||||
|
(In
thousands, except per share amounts)
|
|||||||
|
(Unaudited)
|
|||||||
|
Revenues
|
$
|
207,501
|
$
|
223,168
|
|||
|
Net
income
|
26,437
|
45,882
|
|||||
|
Basic
earnings per common share
|
0.53
|
0.92
|
|||||
|
Diluted
earnings per common share
|
$
|
0.53
|
$
|
0.91
|
|||
|
(3)
|
Summary
of Significant Accounting Policies
|
All
significant accounting policies discussed below are applicable to both the
Company and Calpine unless otherwise noted below.
Principles
of Consolidation/Combination and Basis of Presentation
The
Predecessor combined financial statements for the six months ended June 30,
2005
and year ended December 31, 2004 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 the
Predecessor. The allocations have been made on a reasonable basis and have
been
consistently applied for the periods presented.
The
accompanying consolidated financial statements for the year ended December
31,
2006 and for the six months ended December 31, 2005 contain the accounts of
Rosetta Resources Inc. and its wholly owned subsidiaries after eliminating
all significant intercompany balances and transactions.
Use
of Estimates in Preparation of Financial Statements
The
preparation of the Consolidated/Combined Financial Statements in conformity
with
accounting principles generally accepted in the United States of America
requires management to make estimates and assumptions that affect the reported
amounts of assets and liabilities, and disclosure of contingent assets and
liabilities at the date of the financial statements and the reported amounts
of
revenue and expense during the reporting period. Certain accounting policies
involve judgments and uncertainties to such an extent that there is reasonable
likelihood that materially different amounts could have been reported under
different conditions, or if different assumptions had been used. The Company
evaluates their estimates and assumptions on a regular basis. The Company bases
their estimates on historical experience and various other assumptions that
are
believed to be reasonable under the circumstances, the results of which form
the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results may differ
from
these estimates and assumptions used in preparation of the Company’s financial
statements. The most significant estimates with regard to these financial
statements relate to the provision for income taxes, the outcome of pending
litigation, future development and abandonment costs, estimates to certain
oil
and gas revenues and expenses and estimates of proved oil and natural gas
reserve quantities used to calculate depletion, depreciation and impairment
of
proved oil and natural gas properties and equipment.
Cash and
Cash Equivalents
The
Company considers all highly liquid investments with an original maturity of
three months or less to be cash equivalents.
Allowance
for Doubtful Accounts
The
Company regularly reviews all aged accounts receivables for collectability
and
establishes an allowance as necessary for balances greater than 90 days
outstanding. It is the Company’s belief that there are no balances in accounts
receivable that will not be collected and that an allowance was unnecessary
at
December 31, 2006 and December 31, 2005.
Property,
Plant and Equipment, Net
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 as 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
$3.4 million and $1.7 million of internal costs for the year ended December
31,
2006 and the six months ended December 31, 2005, respectively. Unevaluated
costs
are excluded from the full cost pool and are periodically evaluated for
impairment at which time they are transferred to the full cost pool to be
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.
Our
ceiling test computation was calculated using hedge adjusted market prices
at
December 31, 2006 which were based on a Henry Hub price of $5.64/ MMBtu and
a
West Texas Intermediate oil price of $60.50/Bbl (adjusted for basis and quality
differentials). The use of these prices would have resulted in an after-tax
writedown of $85 million at December 31, 2006. Cash flow hedges of natural
gas
production in place at December 31, 2006 increased the calculated ceiling value
by approximately $47 million (net of tax). However, subsequent to December
31,
2006 the market price for Henry Hub increased to $7.52 MMBtu and the price
for
West Texas Intermediate increased to $61.84/Bbl, and utilizing these prices
our
net capitalized costs of oil and gas properties exceeded the ceiling amount.
As
a result no writedown was recorded at December 31, 2006. The ceiling value
calculated using subsequent prices includes approximately $6 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 prices decline in
the
future, it is possible that a writedown could occur.
No
impairment charge was recorded for the six months ended December 31,
2005.
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.
Calpine
assessed the impairment for oil and natural gas properties on a field by field
basis periodically (at least annually) to determine if impairment of such
properties was necessary. Management utilized its year-end reserve report
prepared by the independent petroleum engineering firm, Netherland,
Sewell & Associates, Inc., and related market factors to estimate the
future cash flows for all proved developed (producing and non-producing) and
proved undeveloped reserves. Property impairments occurred if a field discovered
lower than anticipated reserves, reservoirs produced at a rate below original
estimates or if commodity prices fell below a level that significantly affected
anticipated future cash flows on the property. Proved oil and natural gas
property values were reviewed when circumstances suggested the need for such
a
review and, if required, the proved properties were written down to their
estimated fair market value based on proved reserves and other market factors.
Unproved properties were reviewed quarterly to determine if there was impairment
of the carrying value, with any such impairment charged to expense in the
period. As a result of decreases in proved undeveloped reserves and proved
developed non-producing reserves located in South Texas, in California and
in
the Gulf of Mexico, respectively, a non-cash impairment charge of approximately
$202.1 million was recorded for the year ended December 31, 2004 in the
combined statements of operations. The downward revisions of Calpine’s estimates
were based on the independent reservoir engineer’s year-end reserve report,
which reflected production results and drilling activity that occurred during
2004 and used historical field level and historical decline curves. Due to
significant capital constraints by Calpine, drilling activity was minimized
and
correspondingly the estimate of proved reserves could not be supported through
drilling success or future capital activity and the downward revision was
required. In addition, under the successful efforts method of accounting for
oil
and natural gas properties, individual assets are grouped at the lowest level
for which there are identifiable cash flows. With minimal drilling activity
and
the evaluation of cash flows at this level, proved reserves for South Texas
and
California fields and the Gulf of Mexico had to be revised downward at each
individual field level. No impairment charge was recorded for the six months
ended June 30, 2005.
Other
property, plant and equipment primarily includes furniture, fixtures and
automobiles, which are recorded at cost and depreciated on a straight-line
basis
over useful lives of five to seven years. Repair and maintenance costs are
charged to expense as incurred while renewals and betterments are capitalized
as
additions to the related assets in the period incurred. Gains or losses from
the
disposal of property, plant and equipment are recorded in the period incurred.
The net book value of the property, plant and equipment that is retired or
sold
is charged to accumulated depreciation, asset cost and amortization, and the
difference is recognized as a gain or loss in the results of operations in
the
period the retirement or sale transpires.
Capitalized
Interest
The
Company capitalizes interest on capital invested in projects during the advanced
stages of development and the drilling period in accordance with SFAS
No. 34, “Capitalization of Interest Cost,” (“SFAS No. 34”) as amended
by SFAS No. 58, “Capitalization of Interest Cost in Financial Statements
That Include Investments Accounted for by the Equity Method (an Amendment of
SFAS No. 34).” Upon commencement of production, capitalized interest, as a
component of the total cost of a field is depleted. Financial
Accounting Standards Board (“FASB”) Interpretation No. 33 (“FIN 33”)
provides guidance for the application of SFAS 34 to the full cost method of
accounting for oil and gas properties. Under FIN 33, costs of investments in
unproved properties and major development projects, on which depreciation,
depletion and amortization (“DD&A”) expense is not currently taken and on
which exploration or development activities are in progress, qualify for
capitalization of interest. Capitalized interest is calculated by multiplying
the weighted-average interest rate on debt by the amount of costs excluded.
Capitalized interest cannot exceed gross interest expense.
Fair
Value of Financial Instruments
The
carrying value of cash and cash equivalents, accounts receivable, accounts
payable, notes payable and other payables approximate their respective fair
market values due to their short maturities. As of December 31, 2006, the
carrying value of our debt was approximately $240 million. The fair value of
our
debt approximates the carrying value because the interest rates are based on
floating rates identified by reference to market rates and because the interest
rates charged are at rates at which we can currently borrow.
Income
Taxes
Deferred
income taxes are provided to reflect the tax consequences in future years of
differences between the financial statement and tax basis of assets and
liabilities using the liability method in accordance with the provisions set
forth in SFAS No. 109, “Accounting for Income Taxes”. Income taxes are
provided based on earnings reported for tax return purposes in addition to
a
provision for deferred income taxes and are measured using enacted tax rates
and
laws that will be in effect when the differences are expected to reverse. A
valuation allowance is established to reduce deferred tax assets if it is more
likely than not that the related tax benefits will not be realized.
Concentrations
of Credit Risk
Financial
instruments, which potentially subject the Company to concentrations of credit
risk, consist primarily of cash, accounts receivable and derivative instruments.
The Company’s accounts receivable and derivative instruments are concentrated
among entities engaged in the energy industry within the United
States.
Executory
Contracts
Calpine
had commodity contracts executed by them that did not qualify as leases
under SFAS No. 13, “Accounting for Leases” or derivatives under SFAS
No. 133, “Accounting for Derivative Instruments and Hedging Activities” as
amended by SFAS 138 and SFAS 139 and interpreted by other related accounting
literature. The contracts were classified as executory contracts, and as a
result were accounted for on an accrual basis for the six months ended
June 30, 2005 and the year ended December 31, 2004. The Company had no
contracts classified as executory contracts for the six months ended December
31, 2005 or for the year ended December 31, 2006.
Revenue
Recognition
The
Company uses the sales method of accounting for the sale of its natural gas.
When actual natural gas sales volumes exceed our delivered share of sales
volumes, an over-produced imbalance occurs. To the extent an over-produced
imbalance exceeds our share of the remaining estimated proved natural gas
reserves for a given property, the Company records a liability. At
December 31, 2006 and 2005, imbalances were insignificant.
Since
there is a ready market for natural gas, crude oil and natural gas liquids
(“NGLs”), the Company sells its products soon after production at various
locations at which time title and risk of loss pass to the buyer. Revenue is
recorded when title passes based on the Company’s net interest or nominated
deliveries of production volumes. The Company records its share of revenues
based on production volumes and contracted sales prices. The sales price for
natural gas, crude oil and NGLs are adjusted for transportation cost and
other related deductions. The transportation costs and other deductions are
based on contractual or historical data and do not require significant judgment.
Subsequently, these deductions and transportation costs are adjusted to reflect
actual charges based on third party documents once received by the Company.
Historically, these adjustments have been insignificant. In addition, natural
gas and crude oil volumes sold are not significantly different from the
Company’s share of production.
It
is the
Company’s policy to calculate and pay royalties on natural gas, crude oil and
NGLs in accordance with the particular contractual provisions of the lease,
license or concession agreements and the laws and regulations applicable to
those agreements. Royalty liabilities are recorded in the period in which the
natural gas, crude oil or NGLs are produced and are included in Royalties
Payable on the Company’s Consolidated Balance Sheet.
Derivative
Instruments and Hedging Activities
The
Company uses derivative instruments to manage market risks resulting from
fluctuations in commodity prices of natural gas and crude oil. The Company
periodically enters into derivative contracts, including price swaps or costless
price collars, which may require payments to (or receipts from) counterparties
based on the differential between a fixed price and a variable price for a
fixed
quantity of natural gas or crude oil without the exchange of underlying volumes.
The notional amounts of these financial instruments were based on expected
proved production from existing wells at inception of the hedge
instruments.
Derivatives
are recorded on the balance sheet at fair market value and changes in the fair
market value of derivatives are recorded each period in current earnings or
other comprehensive income, depending on whether a derivative is designated
and
qualifies as a hedge transaction. The Company’s derivatives consist of cash flow
hedge transactions in which the Company is hedging the variability of cash
flows
related to a forecasted transaction. Changes in the fair market value of these
derivative instruments designated as cash flow hedges are reported in other
comprehensive income and reclassified to earnings in the periods in which the
contracts are settled. The ineffective portion of the cash flow hedge is
recognized in current period earnings as other income (expense). Gains and
losses on derivative instruments that do not qualify for hedge accounting are
included in oil and natural gas revenue in the period in which they occur.
The
resulting cash flows from derivatives are reported as cash flows from operating
activities.
At
the
inception of a derivative contract, the Company may designate the derivative
as
a cash flow hedge. For all derivatives designated as cash flow hedges, the
Company formally documents the relationship between the derivative contract
and
the hedged items, as well as the risk management objective for entering into
the
derivative contract. To be designated as a cash flow hedge transaction, the
relationship between the derivative and hedged items must be highly effective
in
achieving the offset of changes in cash flows attributable to the risk both
at
the inception of the derivative and on an ongoing basis. The Company measures
hedge effectiveness on a quarterly basis and hedge accounting is discontinued
prospectively if it is determined that the derivative is no longer effective
in
offsetting changes in the cash flows of the hedged item. Gains and losses
included in accumulated other comprehensive income related to cash flow hedge
derivatives that become ineffective remain unchanged until the related
production is delivered. If the Company determines that it is probable that
a
hedged forecasted transaction will not occur, deferred gains or losses on the
hedging instrument are recognized in earnings immediately. The Company does
not
enter into derivative agreements for trading or other speculative purposes.
See
Note 7 for a description of the derivative contracts which the Company
executes.
Insurance
Program.
CPN
Insurance Corporation, a wholly owned captive insurance subsidiary of Calpine,
charged Calpine premiums to insure worker’s compensation, automobile liability,
and general liability as well as all risk property insurance including business
interruption. Accruals for casualty claims under the captive insurance program
were recorded on a monthly basis, and were based upon the estimate of the total
cost of the claims incurred during the policy period. Accruals for claims under
the captive insurance program pertaining to property, including business
interruption claims, were recorded on a claims-incurred basis. Claims were
accrued on a gross basis before deductibles. The captive provided insurance
coverage with limits up to $25 million per occurrence for property claims,
including business interruption, and up to $500,000 per occurrence for casualty
claims.
Subsequent
to the Acquisition, the Company undertook to obtain insurance coverage from
third party providers.
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 No. 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
$5.7
million and $3.6 million, respectively, for the year ended December 31, 2006.
The effect on net income per share for basic and diluted was a reduction $0.07
for the year ended December 31, 2006. 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.
Any
excess tax benefit is recognized as a credit to additional paid in capital
and
is calculated as the amount by which the tax deduction we receive exceeds the
deferred tax asset associated with the recorded stock compensation expense.
We
have approximately $0.2 million of related excess tax benefits which will be
recognized upon utilization of our net operating loss carryforward.
Treasury
Stock
Shares
of
common stock were repurchased by the Company as the shares were surrendered
by
the 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 the Company’s common stock, nor does the Company have a
publicly announced program to repurchase shares of common stock.
Deferred
Loan Fees
Deferred
loan
fees
incurred in connection with the credit facility are recorded on the Company’s
Consolidated Balance Sheet as deferred loan fees. The deferred loan fees are
amortized to interest expense over a five year period using the straight-line
method, which approximates the effective interest method.
Future
Development and Abandonment Costs
Future
development costs include costs incurred to obtain access to proved reserves
such as drilling costs and the installation of production equipment. Future
abandonment costs include costs to dismantle and relocate or dispose of our
production platforms, gathering systems and related structures and restoration
costs of land and seabed. We develop estimates of these costs for each of our
properties based upon their geographic location, type of production structure,
well depth, currently available procedures and ongoing consultations with
construction and engineering consultants. Because these costs typically extend
many years into the future, estimating these future costs is difficult and
requires management to make judgments that are subject to future revisions
based
upon numerous factors, including changing technology and the political and
regulatory environment. We review our assumptions and estimates of future
development and future abandonment costs on an annual basis.
We
provide for future abandonment costs in accordance with SFAS No. 143,
“Accounting for Asset Retirement Obligations”. This standard requires that a
liability for the discounted fair value of an asset retirement obligation be
recorded in the period in which it is incurred and the corresponding cost
capitalized by increasing the carrying amount of the related long-lived asset.
The liability is accreted to its present value each period, and the capitalized
cost is depreciated over the useful life of the related asset.
Recent
Accounting Developments
The
Fair Value Option for Financial Assets and Financial
Liabilities.
In
February 2007, the FASB issued SFAS No. 159, “The Fair Value Option For
Financial Assets and Financial Liabilities - Including an Amendment of FASB
Statement No. 115” (“SFAS No. 159), which permits an entity to choose to measure
certain financial assets and liabilities at fair value. SFAS No. 159 also
revises provisions of SFAS No. 115 that apply to available-for-sale and trading
securities. This statement is effective for fiscal years beginning after
November 15, 2007. The Company has not yet evaluated the potential impact
of this standard.
Fair
Value Measurements.
In
September 2006, the FASB issued SFAS No. 157,“Fair
Value Measurements” (“SFAS No. 157”), which addresses how companies should
measure fair value when companies are required to use a fair value measure
for
recognition or disclosure purposes under generally accepted accounting
principles (“GAAP”). As a result of SFAS No. 157, there is now a common
definition of fair value to be used throughout GAAP. SFAS No. 157 is effective
for financial statements issued for fiscal years beginning after November 15,
2007, and interim periods within those years. The Company is still assessing
the
impact of this standard but does not expect the adoption of this standard to
have a material impact on the Company’s consolidated financial position, results
of operations, or cash flows.
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
used
the iron curtain method for quantifying financial statement misstatements.
The
Company has applied 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 did not 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. We are
evaluating our tax positions and anticipate that the interpretation will not
have a significant impact on the Company’s retained earnings at the time of
adoption.
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.
|
(4)
|
Accounts
Receivable
|
Accounts
receivable consisted of the following:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Natural
gas, NGLs and oil revenue sales
|
$
|
34,027
|
$
|
35,066
|
|||
|
Joint
interest billings
|
959
|
3,382
|
|||||
|
Short-term
receivable for royalty recoupment
|
1,422
|
1,603
|
|||||
|
Total
|
36,408
|
40,051
|
|||||
|
Less:
allowance for doubtful accounts
|
-
|
-
|
|||||
|
Accounts
receivable, net
|
$
|
36,408
|
$
|
40,051
|
|||
|
(5)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Proved
properties
|
$
|
1,170,223
|
$
|
937,516
|
|||
|
Unproved
properties
|
35,178
|
21,217
|
|||||
|
Gas
gathering systems and compressor stations
|
17,936
|
14,452
|
|||||
|
Other
|
4,562
|
2,912
|
|||||
|
Total
|
1,227,899
|
976,097
|
|||||
|
Less:
Accumulated depreciation, depletion, and amortization
|
(145,289
|
)
|
(40,161
|
)
|
|||
|
$
|
1,082,610
|
$
|
935,936
|
||||
Included
in the Company’s oil and natural gas properties are asset retirement obligations
of $9.6 million and $9.1 million at December 31, 2006 and December 31, 2005,
respectively, including additions of $0.5 million and $9.2 million for the
year
ended December 31, 2006 and the six months ended December 31, 2005,
respectively.
At
December 31, 2006 and 2005, the Company excluded the following capitalized
costs
from amounts subject to depreciation, depletion and amortization:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Onshore:
|
|
|
|||||
|
Development
cost
|
|||||||
|
Incurred
in 2006
|
$
|
-
|
$
|
-
|
|||
|
Incurred
in 2005
|
-
|
1,716
|
|||||
|
Exploration
cost
|
|||||||
|
Incurred
in 2006
|
2,635
|
-
|
|||||
|
Incurred
in 2005
|
-
|
5,212
|
|||||
|
Acquisition
cost of undeveloped acreage
|
|||||||
|
Incurred
in 2006
|
9,976
|
-
|
|||||
|
Incurred
in 2005
|
16,978
|
19,684
|
|||||
|
Capitalized
interest
|
|||||||
|
Incurred
in 2006
|
1,925
|
-
|
|||||
|
Incurred
in 2005
|
228
|
555
|
|||||
|
Total
|
31,742
|
27,167
|
|||||
|
Offshore
|
|||||||
|
Exploration
cost
|
|||||||
|
Incurred
in 2006
|
$
|
-
|
$
|
-
|
|||
|
Incurred
in 2005
|
-
|
2,407
|
|||||
|
Acquisition
costs of undeveloped acreage
|
|||||||
|
Incurred
in 2006
|
5,860
|
||||||
|
Incurred
in 2005
|
-
|
950
|
|||||
|
Capitalized
interest
|
|||||||
|
Incurred
in 2006
|
184
|
-
|
|||||
|
Incurred
in 2005
|
27
|
28
|
|||||
|
Total
|
6,071
|
3,385
|
|||||
|
Total
costs excluded from depreciation, depletion and
amortization
|
37,813
|
30,552
|
|||||
It
is
anticipated that the acquisition of undeveloped acreage and associated
capitalized interest of $35.2 million and exploration costs of $2.6 million
will
be included in capitalized costs subject to depreciation, depletion and
amortization within five years and one year, respectively.
Property
Acquisitions.
During
the fourth quarter of 2006, the Company acquired a 50% working interest in
Main
Pass 29 in the Gulf of Mexico from Andex/Wolf for $16.7 million and a 25%
working interest in Grand Isle 72 in the Gulf of Mexico from Contango Oil and
Gas for $7.0 million.
In
April
2006, the Company also 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.
Gas
Gathering Systems and compressor stations.
The gas
gathering systems and compressor stations of $17.9 million and $14.5 million
for
December 31, 2006 and 2005, respectively, are located in California, the Rocky
Mountains and South Texas. The accumulated depreciation for the gas gathering
systems at December 31, 2006 and 2005 was $1.5 million and $0.5 million,
respectively. The depreciation expense associated with the gas gathering systems
and compressor stations for the year ended December 31, 2006 (Successor), six
months ended December 31, 2005 (Successor), the six months ended June 30, 2005
(Predecessor) and for the year ended December 31, 2004 (Predecessor) was $1.0
million, $0.5 million, $0.6 million and $1.5 million, respectively.
Other
Property and Equipment.
Other
property and equipment at December 31, 2006 and 2005 of $4.6 million and $2.9
million, respectively, consists primarily of furniture and fixtures. The
accumulated depreciation associated with other assets at December 31, 2006
and
2005 was $0.6 million and $0.1 million, respectively. For the year ended
December 31, 2006 (Successor), the six months ended December 31, 2005
(Successor), six months ended June 30, 2005 (Predecessor) and year ended
December 31, 2004 (Predecessor), depreciation expense for these assets was
$0.5
million, $0.1 million, $0.4 million and $0.8 million, respectively.
|
(6)
|
Deferred
Loan Fees
|
At
December 31, 2006 and 2005, deferred loan fees were $3.4 million and $4.6
million, respectively. Total amortization expense for deferred loan fees was
$1.2 million for the year ended December 31, 2006 and $0.6 million for the
six
months ended December 31, 2005.
|
(7)
|
Commodity
Hedging Contracts and Other Derivatives
|
The
Company has entered into financial fixed price swaps with prices ranging from
$6.81 per MMBtu to $8.39 per MMBtu covering a portion of the Company’s 2007,
2008 and 2009 production. The following financial fixed price swap transactions
were outstanding with associated notional volumes and average underlying prices
that represent hedged prices of commodities at various market locations at
December 31, 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)
|
|||||||||||||||
|
2007
|
Swap |
Cash
flow
|
49,341
|
18,009,500
|
$
|
7.76
|
40%
|
|
$
|
17,216
|
||||||||||||
|
2008
|
Swap |
Cash
flow
|
49,909
|
18,266,616
|
7.62
|
44%
|
|
(4,440
|
)
|
|||||||||||||
|
2009
|
Swap |
Cash
flow
|
26,141
|
9,541,465
|
6.99
|
26%
|
|
(5,962
|
)
|
|||||||||||||
|
45,817,581
|
$
|
6,814
|
||||||||||||||||||||
(1)
Estimated based on net gas reserves presented in the December 31, 2006
Netherland, Sewell, & Associates, Inc. reserve report.
The
Company has also entered into 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. If the floating price each
month at the settlement point is greater than the ceiling price, the Company
pays the counterparty an amount equal to the positive difference between the
floating price and the ceiling price multiplied by the notional volume for
the
contract month. If the floating price for each month is less than the floor
price, the counterparty pays the Company an amount equal to the positive
difference between the floating price and the floor price multiplied by the
notional volume for the contract month. 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 December 31, 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)
|
|||||||||||||||
|
2007
|
Costless
Collar
|
Cash
flow
|
10,000
|
3,650,000
|
$
|
7.19
|
$
|
10.03
|
$
|
3,322
|
||||||||||||
|
3,650,000
|
$
|
3,322
|
||||||||||||||||||||
The
total
of proved natural gas production hedged in 2007 for the costless collars is
approximately 8% based on the December 31, 2006 reserve report prepared by
Netherland, Sewell, & Associates, Inc.
The
Company’s current cash flow hedge positions are with counterparties who are also
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 December
31, 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:
|
For
the Year Ended
December
31, 2006
|
For
the Six Months Ended
December
31, 2005
|
||||||
|
Natural
Gas
|
|||||||
|
Quantity
settled (MMBtu)
|
20,075,000
|
7,956,000
|
|||||
|
Increase
(Decrease) in natural gas sales revenue (In thousands)
|
$
|
29,578
|
$
|
(16,576
|
)
|
||
The
Company expects to reclassify gains of $12.8 million based on market pricing
as
of December 31, 2006 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the next
twelve months.
At
December 2006, the Company had derivative assets of $21.2 million, of which
$0.6
million is included in other assets on the Consolidated Balance Sheet. The
Company also had derivative liabilities of $11.0 million on the Consolidated
Balance Sheet at December 31, 2006. The derivative 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 December 31, 2006.
Hedging activities related to cash settlements on commodities increased revenues
by $29.6 million for the year ended December 31, 2006 and decreased revenue
by
$16.6 million for the six months ended December 31, 2005.
Gains
and
losses related to ineffectiveness and derivative instruments not designated
as
hedging instruments are included in other income (expense) and were immaterial
for the year ended December 31, 2006. There was no ineffectiveness related
to
cash-flow hedges recorded for the six months ended December 31, 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) or for the
year
ended December 31, 2004 (Predecessor) as no derivative instruments existed.
|
(8)
|
Accrued
Liabilities
|
The
Company’s accrued liabilities consists of the following:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Accrued
capital costs
|
$
|
21,674
|
$
|
17,607
|
|||
|
Accrued
Calpine settlement (see Note 2)
|
11,400
|
-
|
|||||
|
Accrued
lease operating expense
|
5,252
|
3,202
|
|||||
|
Accrued
payroll and employee incentive expense
|
3,028
|
1,739
|
|||||
|
Other
|
1,745
|
5,849
|
|||||
|
Total
|
$
|
43,099
|
$
|
28,397
|
|||
|
(9)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
For
the Year Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
||||||
|
(In
thousands)
|
|||||||
|
ARO
as of the beginning of the period
|
$
|
9,467
|
$
|
8,789
|
|||
|
Liabilities
incurred during period
|
467
|
447
|
|||||
|
Liabilities
settled during period
|
(33
|
)
|
(121
|
)
|
|||
|
Accretion
expense
|
788
|
352
|
|||||
|
ARO
as of the end of the period
|
$
|
10,689
|
$
|
9,467
|
|||
Of
the
total ARO, approximately $0.4 million is classified as a current liability
at
December 31, 2006 and 2005, respectively. For the year ended December 31, 2006
and six months ended December 31, 2005, the Company recognized depreciation
expense related to its ARO of approximately $1.1 million and $0.4 million,
respectively.
|
(10)
|
Long-Term
Debt
|
Long-term
debt consists of the following:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Senior
secured revolving line of credit
|
$
|
165,000
|
$
|
165,000
|
|||
|
Second
lien term loan
|
75,000
|
75,000
|
|||||
|
240,000
|
240,000
|
||||||
|
Less:
current portion of long-term debt
|
-
|
-
|
|||||
|
$
|
240,000
|
$
|
240,000
|
||||
Senior Secured
Revolving Line of Credit.
BNP
Paribas, in July 2005, provided the Company with a senior secured revolving
line of credit concurrent with the Acquisition in the amount of up to $400.0
million (“Revolver”). This Revolver was syndicated to a group of lenders on
September 27, 2005. Availability under the Revolver is restricted to the
borrowing base, which initially was $275.0 million and was reset to $325.0
million, upon amendment, as a result of the hedges put in place in
July 2005 and the favorable effects of the exercise of the over-allotment
option the Company granted in the Company’s private equity offering in July 2005
through which the Company received $70.0 million of funds (net of transaction
fees). In July 2005, the Company 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 the Company’s 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% (6.85% at December 31,
2006). 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 the Company’s assets,
including a mortgage lien on oil and natural gas properties having at least
80%
of the SEC PV-10 pretax reserve value, a guaranty by all of the Company’s
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. The
Company is 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. In addition, the Company is
subject to covenants limiting dividends and other restricted payments,
transactions with affiliates, incurrence of debt, changes of control, asset
sales, and liens on properties. The
Company was in compliance with all covenants at December 31, 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 December 31,
2006.
Second
Lien Term Loan. BNP
Paribas, in July 2005, also provided the Company with a second lien term
loan concurrent with the acquisition, in the amount of $100.0 million (“Term
Loan”). On September 27, 2005, the Company repaid $25.0 million of
borrowings on the Term Loan, reducing the balance to $75.0 million and
syndicated the Term Loan to a group of lenders including BNP Paribas. Borrowings
under the Term Loan initially bore interest at LIBOR plus 5.00%. As a result
of
the hedges put in place in July 2005 and the favorable effects of the Company’s
private equity placement, as described above, the interest rate for the Term
Loan has been reduced to LIBOR plus 4.00% (9.35% at December 31, 2006). The
loan
is collateralized by second priority liens on substantially all of the Company’s
assets. The Company is 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, the Company is subject to covenants
limiting dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales, and liens on properties.
The Company was in compliance with all covenants at December 31, 2006. The
principal balance of the Term Loan is due and payable on July 7,
2010.
Aggregate
maturities required on long-term debt at December 31, 2006 due in future
years are as follows (In thousands):
|
2007
|
$
|
-
|
||
|
2008
|
-
|
|||
|
2009
|
165,000
|
|||
|
2010
|
75,000
|
|||
|
2011
|
-
|
|||
|
Thereafter
|
-
|
|||
|
Total
|
$
|
240,000
|
|
(11)
|
Commitment
and Contingencies
|
The
Company is party to various oil and natural gas litigation matters arising
out
of the normal course of business. The ultimate outcome of each of these matters
cannot be absolutely determined, and the liability the Company may ultimately
incur with respect to any one of these matters in the event of a negative
outcome may be in excess of amounts currently accrued for with respect to such
matters. Management does not believe any such matters will have a material
adverse effect on the Company’s financial position, results of operations or
cash flows.
Calpine
Bankruptcy
Calpine
Corporation and certain of its subsidiaries filed for protection under the
federal bankruptcy laws in the United States Bankruptcy Court of the Southern
District of New York (the “Bankruptcy Court”) on December 20, 2005. Calpine
Energy Services, L.P., which filed for bankruptcy, has continued to make the
required deposits into the Company’s margin account and to timely pay for
natural gas production it purchases from the Company’s subsidiaries under
various natural gas supply agreements. 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 by Calpine’s creditors. As
to certain other properties, the documentation delivered by Calpine at closing
under the Purchase Agreement was incomplete. The Company remains hopeful that
Calpine will work cooperatively with the Company to secure these ministerial
governmental approvals and to accomplish the curative corrections for all of
these properties. In addition, as to all properties acquired by the Company
in
the Acquisition, Calpine contractually agreed to provide the Company with such
further assurances as the Company may reasonably request. Nevertheless, as
a
result of Calpine’s bankruptcy filing, it remains uncertain as to whether
Calpine will respond cooperatively. If Calpine does not fulfill its contractual
obligations and does not complete the documentation necessary to resolve these
issues, the Company will pursue all available remedies, including but not
limited to a declaratory judgment to enforce the Company’s rights and actions to
quiet title. After pursuing these matters, if the Company experiences a loss
of
ownership with respect to these properties without receiving adequate
consideration for any resulting loss to the Company, an outcome the Company’s
management considers to be remote, then the Company could experience losses
which could have a material adverse effect on the Company’s financial condition,
statement of operations and cash flows.
On
June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to the Company in the Acquisition, to the extent those
leases constitute “unexpired leases of non-residential real property” and were
not fully transferred to the Company at the time of Calpine’s filing for
bankruptcy. According to this motion, Calpine filed in order to avoid the
automatic forfeiture of any interest it may have in these leases by operation
of
a statutory deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to the Company or Calpine, but the
Company understands it was meant to allow Calpine to preserve and avoid
forfeiture under the Bankruptcy Code of whatever interest Calpine may possess,
if any, in these oil and natural gas leases. The Company disputes Calpine’s
contention that it may have an interest in any significant portion of these
oil
and natural gas leases and intends to take the necessary steps to protect all
of
the Company’s rights and interest in and to the leases. On July 7, 2006, the
Company filed an objection in response to Calpine’s motion, wherein the Company
asserted that oil and natural gas leases constitute interests in real property
that are not subject to “assumption” under the Bankruptcy Code. In the objection
the Company also requested that (a) the Bankruptcy Court eliminate from the
order certain Federal offshore leases from the Calpine motion because these
properties were fully conveyed to the Company in July 2005, and the Minerals
Management Service has subsequently recognized the Company as owner and operator
of all but three of these properties, and (b) any order entered by the
Bankruptcy Court be without prejudice to, and fully preserve the Company’s
rights, claims and legal arguments regarding the characterization and ultimate
disposition of the remaining described oil and natural gas properties. In the
Company’s objection, the Company also urged the Bankruptcy Court to require the
parties to promptly address and resolve any remaining issues under the
pre-bankruptcy definitive agreements with Calpine and proposed to the Bankruptcy
Court that the parties seek arbitration (or at least mediation) to complete
the
following:
|
·
|
Calpine’s
conveyance of the Non-Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required
under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company
has
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay Calpine, which the Company
has
concluded is approximately $79 million, consisting of roughly $68
million
for the Non-Consent Properties and approximately $11 million in other
true-up payment obligations.
|
At
a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the California State Lands Commission that the Debtors’ Motion to
Assume Non-Residential Leases and Set Cure Amounts (the “Motion”), did not
allow adequate time for an appropriate response, Calpine withdrew
from the
list of Oil and Gas Leases that were the subject of the Motion those
leases issued by the United States (and managed by the Minerals Management
Service of the United States Department of Interior) (the “MMS Oil and Gas
Leases”) and the State of California (and managed by the California State
Lands Commission) (the “CSLC Leases”). Calpine and both the Department of
Justice and the State of California agreed to an extension of the
existing
deadline to November 15, 2006 to assume or reject the MMS Oil and
Gas
Leases and CSLC Leases under Section 365 of the Bankruptcy Code,
to the
extent the MMS Oil and Gas Leases and CSLC Leases are leases subject
to
Section 365. The effect of these actions was to render the objection
of
the Company inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and the Company to arrive
at a
business solution to all remaining issues including approximately
$68
million payable to Calpine for conveyance of the Non-Consent Properties.
|
On
August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts as well as unliquidated damages in amounts that
can not presently be determined. The
Company continues to work with Calpine on a cooperative and expedited basis
toward resolution of unresolved conveyance of properties and post closing
adjustments under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases, these
parties have further extended this deadline time by stipulation. The deadline
was first extended to January 31, 2007 and recently was further extended to
April 15, 2007 with respect to the MMS Oil and Gas Leases and April 30, 2007
with respect to the CSLC Leases. The Bankruptcy Court entered Orders related
to
the MMS Oil and Gas Leases and CSLC Leases which included appropriate language
that we negotiated with Calpine for our protection in this regard.
Recently,
Calpine sought and obtained an extension to June 20, 2007 from the Bankruptcy
Court for the period in which only Calpine, exclusively, may file its plan
of
reorganization. While there is no assurance that Calpine will file a plan of
reorganization by the exclusively deadline, or that such a plan will be approved
by the creditors and the Bankruptcy Court, the Company remains optimistic that
the issues involving conclusion of the remaining conveyances of the Non-Consent
Properties and obtaining the further assurances from Calpine under the Purchase
Agreement, including perhaps resolution of any and all claims, may occur during
2007.
Calpine
recently requested Bankruptcy Court approval of a new credit facility which
would require it to grant liens to these new lenders in all of its assets,
including any interest it may still hold in any oil and gas properties it
obligated itself to convey to the Company under the Purchase Agreement. The
Bankruptcy Court entered an Order approving Calpine’s ability to obtain this new
loan which includes appropriate language that the Company negotiated with
Calpine for the Company’s protection in this regard
However,
there can be no assurance that Calpine, its creditors or other interest holders
will not challenge the fairness of the Acquisition. For a number of reasons,
including the Company’s understanding of the process that Calpine followed in
allowing market forces to set the purchase price for the Acquisition, the
Company believes that it is unlikely that any challenges by the Calpine debtors
or their creditors to the overall fairness of the Acquisition would be
successful. The Company will take all necessary action to ensure the Company’s
rights under the Purchase agreement, the MMS Oil and Gas Leases, the CSLC Leases
and the Bankruptcy Code are fully protected.
Arbitration
between Calpine Corp./RROLP and Pogo Producing
Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of the sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming, that certain leases
subject to the sale had expired because of lack of production. Calpine had
undertaken without success to resolve this matter by obtaining ratifications
of
a majority of the questionable leases. Calpine filed for bankruptcy protection
before Pogo filed arbitration against it. Even though this is a retained
liability of Calpine, Calpine declined to accept the Company’s tender of defense
and indemnity when Pogo filed for arbitration against the Company. The Company
filed a motion to abate this arbitration which was denied by the arbitration
panel and an adversary proceeding in the Calpine Bankruptcy Court requesting
the
Bankruptcy Court extend the automatic stay of the Bankruptcy Code to Pogo’s
arbitration claim. The Calpine debtors and creditors committee intervened in
this adversary proceeding in support of the Company’s request and also jointly
opposed Pogo’s motion to dismiss our adversary proceeding. The Bankruptcy Court
denied Pogo’s motion to dismiss the adversary proceeding. This is a retained
liability by Calpine and it is too early for management to determine whether
this matter will have any financial impact to the Company.
Environmental
Environmental
expenditures are expensed or capitalized, as appropriate, depending on their
future economic benefit. Expenditures that relate to an existing condition
caused by past operations, and that do not have future economic benefit, are
expensed. Liabilities related to future costs are recorded on an undiscounted
basis when environmental assessments and/or remediation activities are probable
and the cost can be reasonably estimated. The Company performed an environmental
remediation study for two sites in California and correspondingly, recorded
a
liability, which at December 31, 2006 and 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 December 31, 2006
as
the study is still in the preliminary stage.
Lease
Obligations and Other Commitments
The
Company has operating leases for office space and other property and equipment.
The Company incurred lease rental expense of $2.4 million and $ 0.6 million
for the year ended December 31, 2006 and six months ended December 31,
2005. For the six months ended June 30, 2005 (predecessor) and for the year
ended December 31, 2004 (predecessor) the expense for office lease and
building maintenance was allocated by Calpine Corporation on a square footage
basis coinciding with the move to Calpine Center in 2004. The expense allocated
was $1.1 million and $1.6 million, respectively, for the six months ended
June 30, 2005 (predecessor) and the year ended December 31, 2004
(predecessor).
Future
minimum annual rental commitments under non-cancelable leases at
December 31, 2006 are as follows (In thousands):
|
2007
|
$
|
2,421
|
||
|
2008
|
2,234
|
|||
|
2009
|
1,965
|
|||
|
2010
|
1,867
|
|||
|
2011
|
1,915
|
|||
|
Thereafter
|
3,978
|
|||
|
$
|
14,380
|
The
Company has drilling rig commitments of $14.9 million for 2007.
|
(12)
|
Stock-Based
Compensation
|
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 and for the year ended
December 31, 2004 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 Accounting Principles Board Opinion
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 six
months ended December 31, 2005 as reported and on a pro forma basis as if the
fair value method prescribed by SFAS No. 123 had been applied.
|
Successor
|
||||
|
Six
Months Ended December 31, 2005
|
||||
|
(In
thousands)
|
||||
|
Net
income, as reported
|
$
|
17,535
|
||
|
Deduct:
stock-based employee compensation expense determined under the fair
value
method for all awards, net of related tax effects
|
(630
|
)
|
||
|
Pro
forma net income
|
$
|
16,905
|
||
|
Net
income per share:
|
||||
|
Basic,
as reported
|
$
|
0.35
|
||
|
Basic,
pro forma
|
$
|
0.34
|
||
|
Diluted,
as reported
|
$
|
0.35
|
||
|
Diluted,
pro forma
|
$
|
0.34
|
||
Adoption
of SFAS-123R
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 year ended
December 31, 2006 was $5.7 million with an associated tax benefit of $2.1
million. Stock-based compensation expense for the six months ended December
31,
2005 was $4.2 million with an associated tax benefit of $1.6 million. For the
six months ended June 30, 2005 (Predecessor) and year ended December 31, 2004
(Predecessor), stock-based compensation expense recorded was $0.2 million with
a
tax benefit of $0.1million and $0.1 million with a tax benefit of less than
$0.1
million, respectively. The remaining compensation expense associated with total
unvested awards as of December 31, 2006 was $9.3 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 options vest over a three year
period.
The
weighted average fair value at date of grant for options granted during the
year
ended December 31, 2006 and six months ended December 31, 2005 was $ 10.71
per
share and $9.59 per share, respectively. 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
|
|||||||
|
Year
Ended
December
31, 2006
|
Six
Months Ended
December
31, 2005
|
||||||
|
Expected
option term (years)
|
6.5
|
6.5
|
|||||
|
Expected
volatility
|
56.65
|
%
|
54.62
|
%
|
|||
|
Expected
dividend rate
|
0.00
|
%
|
0.00
|
%
|
|||
|
Risk
free interest rate
|
4.33%
- 5.15
|
%
|
4.03%
- 4.60
|
%
|
|||
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 December 31, 2006:
|
Shares
|
Weighted
Average Exercise Price
Per
Share
|
Weighted
Average Remaining Contractual Term
(In
years)
|
Aggregate
Intrinsic Value
(In
thousands)
|
||||||||||
|
Outstanding
at December 31, 2005
|
706,550
|
$
|
16.28
|
||||||||||
|
Granted
|
290,950
|
17.89
|
|||||||||||
|
Exercised
|
(49,896
|
)
|
16.09
|
||||||||||
|
Forfeited
|
(94,250
|
)
|
16.64
|
||||||||||
|
Outstanding
at December 31, 2006
|
853,354
|
$
|
16.80
|
8.80
|
$
|
1,491
|
|||||||
|
Options
Vested and Exercisable at December 31, 2006
|
348,378
|
$
|
16.42
|
8.67
|
$
|
741
|
|||||||
Stock-based
compensation expense recorded for stock option awards for the year ended
December 31, 2006 is $2.9 million. There was no stock-based compensation expense
for stock option awards for the six months ended December 31, 2005. Unrecognized
expense as of December 31, 2006 for all outstanding stock options is $5.0
million and will be recognized over a weighted average period of 1.29
years.
The
total
intrinsic value of options exercised during the year ended December 31, 2006
is
$0.1 million. There were no options exercised for the six months ended December
31, 2005.
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 December 31, 2006:
|
Shares
|
Weighted
Average Grant Date Fair Value
|
||||||
|
Non-vested
shares outstanding at December 31, 2005
|
581,900
|
$
|
16.27
|
||||
|
Granted
|
155,523
|
17.76
|
|||||
|
Vested
|
(352,398
|
)
|
16.16
|
||||
|
Forfeited
|
(58,125
|
)
|
16.54
|
||||
|
Non-vested
shares outstanding at December 31, 2006
|
326,900
|
$
|
17.05
|
||||
The
non-vested restricted stock outstanding at December 31, 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. The fair value of awards vested for the year ended December 31, 2006
was
$6.5 million.
Stock-based
compensation expense recorded for restricted stock awards for the year ended
December 31, 2006 and the six months ended December 31, 2005 was $2.8 million
and $4.2 million, respectively. Unrecognized expense as of December 31, 2006
for
all outstanding restricted stock awards is $4.3 million and will be recognized
over a weighted average period of 1.42 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. Employer profit-sharing contributions in 2004 totaled
$0.4
million.
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. For the six months ended June 30, 2005 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 year ended December 31, 2004, there were 91,809 shares issued
to Calpine’s employees at a weighted average fair market value of $3.26 per
share. 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 and year ended December 31, 2004, compensation
expense of $0.2 million and $0.1 million, respectively, 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 ten years. No options were exercised for the six months ended
June
30, 2005 or for the year ended December 31, 2004. As of June 30, 2005, the
amount of shares outstanding under the 1996 incentive plan were
754,284.
The
range
of fair values at the date of grant for Calpine options granted during the
six
months ended June 30, 2005 and for the year ended December 31, 2004 was $1.27
per share and $1.99 to $4.56 per share, respectively. The fair value of options
granted is estimated on the date of grant using the Black-Scholes option-pricing
model with the following assumptions:
|
Predecessor
|
|||||||
|
Six
Months Ended
June
30, 2005
|
Year
Ended
December
31, 2004
|
||||||
|
Expected
option term (years)
|
2.5
|
3
- 9.5
|
|||||
|
Expected
volatility
|
58.00
|
%
|
77%
- 98
|
%
|
|||
|
Expected
dividend rate
|
0.00
|
%
|
0.00
|
%
|
|||
|
Risk
free interest rate
|
3.62
|
%
|
2.57%
- 4.02
|
%
|
|||
|
(13)
|
Income
Taxes
|
Under
SFAS No. 109, “Accounting for Income Taxes,” deferred tax assets and
liabilities are determined based on differences between the financial reporting
and tax basis of assets and liabilities, and are measured using enacted tax
rates and laws that will be in effect when the differences are expected to
reverse.
At
December 31, 2006, the Company had a deferred tax asset related to net
operating loss carryforwards of approximately $82.0 million. Approximately
$5.0
million of the net operating loss carryforward will expire in 2025. The
remaining amount expires in 2026. The federal and state net operating loss
carryforwards available are subject to limitations on their annual usage.
Realization of the deferred tax assets and net operating loss carryforwards
is
dependent, in part, on generating sufficient taxable income prior to expiration
of the loss carryforwards. The amount of the deferred tax asset considered
realizable, however, could be reduced in the near term if estimates of future
taxable income during the carryforward period are reduced. There is no valuation
allowance recorded on this deferred tax asset as the Company believes it is
more
likely than not that the asset will be utilized.
The
Company’s income tax expense (benefit) from continuing operations consists of
the following:
|
Successor
|
Predecessor
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
(In
thousands)
|
|||||||||||||||
|
Current:
|
|||||||||||||||
|
Federal
|
$
|
-
|
$
|
-
|
$
|
7,556
|
$
|
25,452
|
|||||||
|
State
|
172
|
-
|
1,067
|
3,670
|
|||||||||||
|
172
|
-
|
8,623
|
29,122
|
||||||||||||
|
Deferred:
|
|||||||||||||||
|
Federal
|
24,132
|
10,139
|
2,519
|
(68,078
|
)
|
||||||||||
|
State
|
3,340
|
1,398
|
354
|
(9,569
|
)
|
||||||||||
|
27,472
|
11,537
|
2,873
|
(77,647
|
)
|
|||||||||||
|
Total
income tax expense (benefit)
|
$
|
27,644
|
$
|
11,537
|
$
|
11,496
|
$
|
(48,525
|
)
|
||||||
The
differences between income taxes computed using the statutory federal income
tax
rate and that shown in the statement of operations from continuing operations
are summarized as follows:
|
Successor
|
Predecessor
|
||||||||||||||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||||||||||||||
|
(In
thousands)
|
(%)
|
(In
thousands)
|
(%)
|
(In
thousands)
|
(%)
|
(In
thousands)
|
(%)
|
||||||||||||||||||||
|
|
|||||||||||||||||||||||||||
|
US
Statutory Rate
|
$
|
25,288
|
35.0
|
%
|
$
|
10,175
|
35.0
|
%
|
$
|
10,562
|
35.0
|
%
|
$
|
(44,576
|
)
|
35.0
|
%
|
||||||||||
|
State
income tax, net of federal benefit
|
2,283
|
3.2
|
%
|
909
|
3.1
|
%
|
924
|
3.1
|
%
|
(3,896
|
)
|
3.1
|
%
|
||||||||||||||
|
Transaction
costs not deductible
|
-
|
0.0
|
%
|
466
|
1.6
|
%
|
-
|
0.0
|
%
|
-
|
0.0
|
%
|
|||||||||||||||
|
Permanent
differences and other
|
73
|
0.0
|
%
|
(13
|
)
|
0.0
|
%
|
10
|
0.0
|
%
|
(53
|
)
|
0.0
|
%
|
|||||||||||||
|
Total
tax expense (Benefit)
|
$
|
27,644
|
38.2
|
%
|
$
|
11,537
|
39.7
|
%
|
$
|
11,496
|
38.1
|
%
|
$
|
(48,525
|
)
|
38.1
|
%
|
||||||||||
The
effective tax rate in all periods is the result of the earnings in various
domestic tax jurisdictions that apply a broad range of income tax rates. The
provision for income taxes differs from the tax computed at the federal
statutory income tax rate due primarily to state taxes, tax credits and other
permanent differences. Future effective tax rates could be adversely affected
if
earnings are lower than anticipated, if unfavorable changes in tax laws and
regulations occur, or if the Company experiences future adverse determinations
by taxing authorities.
The
components of deferred taxes are as follows:
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Deferred
tax assets
|
|||||||
|
Accrued
liabilities not currently deductible
|
$
|
1,410
|
$
|
1,614
|
|||
|
Other
reserves not currently deductible
|
413
|
276
|
|||||
|
Hedge
activity
|
-
|
31,093
|
|||||
|
Net
operating loss carryforward
|
30,428
|
608
|
|||||
|
Total
deferred tax assets
|
32,251
|
33,591
|
|||||
|
Oil
and gas basis differences
|
(71,142
|
)
|
(14,007
|
)
|
|||
|
Depreciation
|
(120
|
)
|
(28
|
)
|
|||
|
Hedge
activity
|
(3,821
|
)
|
-
|
||||
|
Total
gross deferred tax liabilities
|
(75,083
|
)
|
(14,035
|
)
|
|||
|
Net
deferred tax assets (liabilities)
|
$
|
(42,832
|
)
|
$
|
19,556
|
||
|
(14)
|
Earnings
Per Share
|
Basic
earnings per share (“EPS”) 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
|
Predecessor
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
(In
thousands)
|
|||||||||||||||
|
Basic
weighted average number of shares outstanding
|
50,237
|
50,003
|
50,000
|
50,000
|
|||||||||||
|
Dilution
effect of stock option and awards at the end of the period
|
171
|
186
|
160
|
-
|
|||||||||||
|
Diluted
weighted average number of shares outstanding
|
50,408
|
50,189
|
50,160
|
50,000
|
|||||||||||
|
Stock
awards and shares excluded from diluted earnings per share due to
anti-dilutive effect
|
198
|
-
|
-
|
160
|
|||||||||||
In
July
2005, the Company was capitalized with fifty million shares of common stock,
through a private placement of 45,312,500 shares of the Company’s common stock
to qualified institutional buyers and non-U.S. persons in transactions exempt
from registration under the Securities Act of 1933 and through an exempt
transaction in connection with the Acquisition. Additionally, the Company sold
4,687,500 shares of the Company’s common stock in an exempt transaction on
July 14, 2005 for proceeds of $70 million (net of transaction costs) which
were used to repay $60 million of debt under the Company’s new revolving credit
facility with the remaining amount used to fund unspecified operating costs
and
general and administrative costs of oil and natural gas operations. In
accordance with SEC Staff Accounting Bulletin No. 98, this capitalization
has been retroactively reflected for purposes of calculating earnings per share
for all prior periods presented in the accompanying statements of
operations.
|
(15)
|
Operating
Segments
|
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 the United States or its territorial waters. Geographic revenue and
property, plant and equipment information below are based on physical location
of the assets at the end of each period.
|
Successor
|
Predecessor
|
||||||||||||||
|
Year
Ended December 31, 2006 (1)
|
Six
Months Ended December 31, 2005 (1)
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
Oil
and Natural Gas Revenue
|
(In
thousands)
|
||||||||||||||
|
California
|
$
|
76,408
|
$
|
48,138
|
$
|
43,385
|
$
|
108,320
|
|||||||
|
Lobo
|
71,450
|
39,062
|
26,474
|
62,417
|
|||||||||||
|
Perdido
|
29,538
|
14,675
|
12,380
|
21,200
|
|||||||||||
|
State
Waters
|
8,183
|
6,761
|
2,345
|
88
|
|||||||||||
|
Other
Onshore
|
25,878
|
9,364
|
7,662
|
13,734
|
|||||||||||
|
Gulf
of Mexico
|
26,734
|
9,921
|
10,542
|
40,195
|
|||||||||||
|
Rocky
Mountains
|
2,115
|
338
|
161
|
284
|
|||||||||||
|
Mid-Continent
|
1,879
|
1,309
|
842
|
1,549
|
|||||||||||
|
Other
|
-
|
112
|
40
|
-
|
|||||||||||
|
$
|
242,185
|
$
|
129,680
|
$
|
103,831
|
$
|
247,787
|
||||||||
|
Successor
|
|||||||
|
December
31,
|
|||||||
|
2006
|
2005
|
||||||
|
Oil
and Natural Gas Properties (2)
|
(In
thousands)
|
||||||
|
California
|
$
|
435,167
|
$
|
386,513
|
|||
|
Lobo
|
426,348
|
368,276
|
|||||
|
Perdido
|
52,702
|
25,983
|
|||||
|
State
Waters
|
26,922
|
12,067
|
|||||
|
Other
Onshore
|
102,734
|
75,737
|
|||||
|
Gulf
of Mexico
|
125,425
|
77,416
|
|||||
|
Rocky
Mountains
|
44,455
|
21,224
|
|||||
|
Mid-Continent
|
9,584
|
5,969
|
|||||
|
Other
|
4,562
|
2,912
|
|||||
|
$
|
1,227,899
|
$
|
976,097
|
||||
|
(1)
|
Excludes
the effects of hedging.
|
|
(2)
|
Oil
and natural gas properties at December 31, 2006 and 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.
|
Major
Customers
For
the
year ended December 31, 2006, the Company had two major customers, which
accounted for approximately 60% of the Company’s consolidated annual revenue.
Calpine Energy Services (“CES”), a Calpine affiliate, was one of the major
customers. The Company’s annual consolidated revenue from CES accounted for
approximately 45% and 80% for the year ended December 31, 2006 and six months
ended December 31, 2005, respectively, and is reflected in oil and natural
gas
sales. For the six months ended June 30, 2005 and the year ended December 31,
2004, CES also accounted for approximately 75% of Calpine’s annual combined
revenues, which is reflected as oil and natural gas sales to affiliates. See
Note 17 for a discussion of the Company’s activity with CES.
For
the
year ended December 31, 2006 and six months ended December 31, 2005,
revenues from sales to CES were $99.1million and $75.0 million, respectively.
There was no receivable from CES at December 31, 2006 or 2005. For the six
months ended June 30, 2005 and the year ended December 31, 2004, revenues
from sales to CES were $82.0 million and $190.2 million, respectively. Under
the
gas purchase and sale contract, CES is required to collateralize payments under
the contract by daily margin payments into the Company’s collateral account,
which are then settled at the end of the month. At December 31, 2006 and 2005,
the Company had $17.9 million and $14.5 million in the margin account for
December sales to CES which is included in other current liabilities on the
Consolidated Balance Sheet.
Marketing
Services Agreement
The
Company entered into a marketing and services agreement (“MSA”) with Calpine
Producer Services (“CPS”) in July 2005 for the period through June 30,
2007. The MSA covers all the Company’s current and future production during the
term of the MSA. Additionally, CPS provides services related to the sale of
the
Company’s production including nominating, scheduling, balancing and other
customary marketing services and assists the Company with volume reconciliation,
well connections, credit review, training, severance and other similar taxes,
royalty support documentation, contract administration, billing, collateral
management and other administrative functions. All CPS activities are performed
as agent and on the Company’s behalf, and under the Company’s control and
direction. The fee payable by the Company under the MSA is based on net proceeds
of all commodity sales multiplied by 0.75%. For the year ended December 31,
2006
and the six months ended December 31, 2005, the fee was approximately $2.3
million and $1.4 million, respectively. The Company can request a reduction
in
the fee if the Company’s volume increases to 130,000 MMBtu per day and 190,000
MMBtu per day to 0.625% and 0.50% respectively. The MSA provides that all
contracts, agreements, collateral and funds related to the marketing and sales
activity be contracted directly with the Company or the Company’s designee, and
paid directly to the Company.
|
(16)
|
Discontinued
Operations
|
On
September 1, 2004, Calpine completed the sale of its Rocky Mountain natural
gas properties that were primarily concentrated in two geographic areas: the
Colorado Piceance Basin and the New Mexico San Juan Basin. Together, these
assets represented approximately 120 billion cubic feet equivalent (“Bcfe”) of
proved natural gas reserves, producing approximately 16.3 million net cubic
feet equivalent (“MMcfe”) per day of natural gas as of September 1, 2004.
Under the terms of the agreement, Calpine received net cash proceeds of
approximately $218.7 million, and recorded a pre-tax gain of approximately
$103.7 million.
The
tables below present significant components of the Company’s income from
discontinued operations for the year ended December 31, 2004:
|
Predecessor
|
||||
|
Year
Ended December 31, 2004
|
||||
|
(In
thousands)
|
||||
|
Total
Revenue
|
$
|
23,081
|
||
|
Gain
(loss) on disposal before taxes
|
103,707
|
|||
|
Operating
income from discontinued operations before taxes
|
7,823
|
|||
|
Income
from discontinued operations before taxes
|
111,530
|
|||
|
Income
tax provision
|
(43,090
|
)
|
||
|
Income
from discontinued operations, net of tax
|
$
|
68,440
|
||
At
December 31, 2004, there were no assets of discontinued operations as the
assets were sold in September 2004.
Calpine
allocated interest to discontinued operations in accordance with EITF Issue
No. 87-24, “Allocation of Interest to Discontinued Operations.” Calpine
included interest expense on debt that was required to be repaid as a result
of
a disposal transaction in discontinued operations. Additionally, other interest
expense that cannot be attributed to other operations of Calpine was allocated
based on the ratio of net assets to be sold less debt that is required to be
paid as a result of the disposal transaction to the sum of total net assets
of
Calpine plus combined debt of Calpine, excluding (a) debt of the
discontinued operation that will be assumed by the buyer, (b) debt that is
required to be paid as a result of the disposal transaction and (c) debt
that can be directly attributed to other operations of Calpine.
|
(17)
|
Related
Party Transactions
|
Successor
During
the year ended December 31, 2006 and six months ended December 31, 2005,
the Company purchased accounting contract services from a firm in which a
principal partner is related to an officer of the Company. Total expenditures
for these services were $1.0 million and $0.6 million,
respectively.
The
Company provided LOTO Energy, LLC (“LOTO I”) certain services for a fee pursuant
to an administrative services agreement that ended on June 30, 2006. LOTO I
is
indirectly owned in part by family trusts established by our director G. Louis
Graziadio, III. Additionally, in January 2006, the Company purchased certain
leases from LOTO Energy II, LLC (“LOTO II”) for cash, subject to a retained
overriding royalty in favor of LOTO II. The Company also made certain ongoing
development commitments to LOTO II associated with these leases. LOTO II is
indirectly owned in part by family trusts established by Mr. Graziadio who
was
its president at the time of this purchase.
Predecessor
Calpine
and certain of Calpine’s affiliates have entered into various agreements with
respect to the domestic oil and natural gas properties. These contracts were
all
cancelled at the date of the Acquisition of the oil and natural gas business
by
the Company. Following is a general description of each of the various
agreements:
Agency
Agreement.
Calpine
entered into a service agreement with CPS beginning April 1, 2003. The
contract automatically renewed every year unless terminated by either party.
CPS
provided services related to Calpine’s production, including marketing, contract
administration, royalty and working interest owner issues, and receipt of
payments. All activities performed by CPS were performed on behalf of Calpine
and under Calpine’s control and direction, in exchange for a fee for services
rendered. Calpine dispensed all royalty payments when CPS provided accurate
and
timely details. Management fees of $0.9 million and $1.9 million for the six
months ended June 30, 2005 and year ended December 31, 2004, respectively,
were recorded as Affiliated marketing fees in the Consolidated/Combined
Statements of Operations.
Natural
Gas Sales.
Calpine
and CES executed index based natural gas sales under master agreements. Many
of
these transactions were executed by CPS on behalf of Calpine; however, Calpine
sold directly to CPS and CES prior to the agency agreement with CPS being
executed. Oil and natural gas sales to affiliates were $81.9 million for the
six
months ended June 30, 2005 and $190.2 million a for the year ended
December 31, 2004 .
Natural
gas balancing activities between CES and Calpine, where Calpine bought back
natural gas above the needs of CES and then re-sold that excess natural gas
to
third parties was recorded net to Affiliated marketing fees in the
Consolidated/Combined Statements of Operations. The net effect of these
balancing activities resulted in a gain or loss in the respective period. The
net balancing cost (reduction of cost) for the year ended December 31, 2004
was $(0.1) million. There was no net balancing cost for the six months ended
June 30, 2005.
Notes
Payable to Affiliates.
Prior to
the acquisition in July 2005, the Company and Calpine had an agreement whereby
Calpine loaned the Company funds for capital expenditures, as well as operating
costs. The Company repaid the balance of the note to Calpine as excess cash
was
available from continuing operations and asset sales. Interest on the note
was
compounded monthly at an annual rate of 8.75% during 2002 and 2003 and for
the
period through July of 2004, when the rate became variable, raising from 9.0%
in
August 2004 to 9.05% in December 2004. Additionally, the Company received
equipment transferred from CPN Pipeline Company (“Pipeline”) during 2004 that
was transferred at historical cost as the transaction was between entities
under
common control. The Company’s payable to Pipeline was subsequently transferred
to Calpine and increased the note discussed above. As part of certain credit
facilities entered into by Calpine, the security included direct liens on the
domestic oil and natural gas properties. The balance of Notes payable to
Affiliates was $127.2 million at December 31, 2004. Notes payable of $92.9
million were retired at the time of the Acquisition.
Other
Services.
Calpine
provided general services to other subsidiaries of Calpine that were recorded
in
other revenue on the Consolidated/Combined Statements of Operations, which
were
insignificant.
Supplemental
Oil and Gas Disclosures
(Unaudited)
The
following disclosures for the Company are made in accordance with Statement
of
Financial Accounting Standards (“SFAS”) No. 69, “Disclosures About Oil and
Natural gas Producing Activities (an amendment of FASB Statements 19, 25, 33
and
39)” (“SFAS No. 69”). Users of this information should be aware that the
process of estimating quantities of proved, proved developed and proved
undeveloped crude oil and natural gas reserves is very complex, requiring
significant subjective decisions in the evaluation of all available geological,
engineering and economic data for each reservoir. The data for a given reservoir
may also change substantially over time as a result of numerous factors
including, but not limited to, additional development activity, evolving
production history and continual reassessment of the viability of production
under varying economic conditions. Consequently, material revisions to existing
reserve estimates occur from time to time. Although every reasonable effort
is
made to ensure that reserve estimates reported represent the most accurate
assessments possible, the significance of the subjective decisions required
and
variances in available data for various reservoirs make these estimates
generally less precise than other estimates presented in connection with
financial statement disclosures.
Proved
reserves represent estimated quantities of natural gas and crude oil that
geological and engineering data demonstrate, with reasonable certainty, to
be
recoverable in future years from known reservoirs under economic and operating
conditions existing at the time the estimates were made.
Proved
developed reserves are proved reserves expected to be recovered, through wells
and equipment in place and under operating methods being utilized at the time
the estimates were made.
Proved
undeveloped reserves are reserves that are expected to be recovered from new
wells on undrilled acreage or from existing wells where a relatively major
expenditure is required for recompletion. Reserves on undrilled acreage are
limited to those drilling units offsetting productive units that are reasonably
certain of production when drilled. Proved reserves for other undrilled units
can be claimed only where it can be demonstrated with certainty that there
is
continuity of production from the existing productive formation. Estimates
for
proved undeveloped reserves are not attributed to any acreage for which an
application of fluid injection or other improved recovery technique is
contemplated, unless such techniques have been proved effective by actual tests
in the area and in the same reservoir.
Estimates
of proved developed and proved undeveloped reserves as of December 31,
2006, 2005 and 2004, were based on estimates made by our independent engineers,
Netherland, Sewell & Associates, Inc. Netherland, Sewell &
Associates, Inc., are engaged by and provide their reports to our senior
management team. We make representations to the independent engineers that
we
have provided all relevant operating data and documents, and in turn, we review
these reserve reports provided by the independent engineers to ensure
completeness and accuracy. Our Chairman of the Board, President and Chief
Executive Officer makes the final decision on booked proved reserves by
incorporating the proved reserves from the independent engineers’
reports.
Our
relevant management controls over proved reserve attribution, estimation and
evaluation include:
|
·
|
Controls
over and processes for the collection and processing of all pertinent
operating data and documents needed by our independent reservoir
engineers
to estimate our proved reserves;
and
|
|
·
|
Engagement
of well qualified and independent reservoir engineers for review
of our
operating data and documents and preparation of reserve reports annually
in accordance with all SEC reserve estimation
guidelines.
|
Market
prices as of each year-end were used for future sales of natural gas, crude
oil
and natural gas liquids. Future operating costs, production and ad valorem
taxes
and capital costs were based on current costs as of each year-end, with no
escalation. There are numerous uncertainties inherent in estimating quantities
of proved reserves and in projecting the future rates of production and timing
of development expenditures. Reserve data represent estimates only and should
not be construed as being exact. Moreover, the standardized measure should
not
be construed as the current market value of the proved oil and natural gas
reserves or the costs that would be incurred to obtain equivalent reserves.
A
market value determination would include many additional factors including
(a) anticipated future changes in natural gas and crude oil prices,
production and development costs, (b) an allowance for return on
investment, (c) the value of additional reserves, not considered proved at
present, which may be recovered as a result of further exploration and
development activities, and (d) other business risk.
In
accordance with SFAS No. 144 “Accounting for Impairment or Disposal of
Long-Lived Assets” (“SFAS No. 144”), United States natural gas reserves and
petroleum asset divestments were accounted for as discontinued operations in
preparing SFAS No. 69 data.
Capitalized
Costs Relating to Oil and Gas Producing Activities
The
following table sets forth the capitalized costs relating to the Company’s
natural gas and crude oil producing activities at December 31, 2006 and
2005:
|
Successor
|
|||||||
|
2006
|
2005
|
||||||
|
(In
thousands)
|
|||||||
|
Proved
properties
|
$
|
1,170,223
|
$
|
937,516
|
|||
|
Unproved
properties
|
35,178
|
21,217
|
|||||
|
Total
|
1,205,401
|
958,733
|
|||||
|
Less:
Accumulated depreciation, depletion, and amortization
|
(143,216
|
)
|
(39,546
|
)
|
|||
|
Net
capitalized costs
|
$
|
1,062,185
|
$
|
919,187
|
|||
|
Company's
share of equity method investees' net capitalized costs
|
$
|
1,166
|
$
|
1,225
|
|||
Pursuant
to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net
capitalized cost includes asset retirement cost of $9.6 million and $9.1 million
as of December 31, 2006, and December 31, 2005,
respectively.
Costs
Incurred in Oil and Natural Gas Property Acquisition, Exploration and
Development Activities
The
following table sets forth costs incurred related to the Company’s oil and
natural gas activities for the year ended December 31, 2006 (Successor), six
months ended December 31, 2005 (Successor), June 30, 2005
(Predecessor) and for the year ended December 31, 2004
(Predecessor):
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
(In
thousands)
|
|||||||
|
Year
Ended December 31, 2006 (Successor)
|
|||||||
|
Acquisition
costs of properties
|
|||||||
|
Proved
|
$
|
39,194
|
$
|
-
|
|||
|
Unproved
|
22,317
|
-
|
|||||
|
Subtotal
|
61,511
|
-
|
|||||
|
Exploration
costs
|
48,446
|
-
|
|||||
|
Development
costs
|
125,971
|
-
|
|||||
|
Total
|
$
|
235,928
|
$
|
-
|
|||
|
Company's
share of equity method investees' costs of property acquisition,
exploration and development
|
$
|
61
|
$
|
-
|
|||
|
Six
months ended December 31, 2005 (Successor)
|
|||||||
|
Acquisition
costs of properties
|
|||||||
|
Proved
|
$
|
915,700
|
$
|
-
|
|||
|
Unproved
|
21,930
|
-
|
|||||
|
Subtotal
|
937,630
|
-
|
|||||
|
Exploration
costs
|
19,294
|
-
|
|||||
|
Development
costs
|
35,915
|
-
|
|||||
|
Total
|
$
|
992,839
|
$
|
-
|
|||
|
Company's
share of equity method investees' costs of property acquisition,
exploration and development
|
$
|
181
|
$
|
-
|
|||
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
(In
thousands)
|
|||||||
|
Six
months ended June 30, 2005 (Predecessor)
|
|||||||
|
Acquisition
costs of properties
|
|||||||
|
Proved
|
$
|
-
|
$
|
-
|
|||
|
Unproved
|
1,640
|
-
|
|||||
|
Subtotal
|
1,640
|
-
|
|||||
|
Exploration
costs
|
13,110
|
-
|
|||||
|
Development
costs
|
20,233
|
-
|
|||||
|
Total
|
$
|
34,983
|
$
|
-
|
|||
|
Company's
share of equity method investees' costs of property acquisition,
exploration and development
|
$
|
25
|
$
|
-
|
|||
|
Year
Ended December 31, 2004 (Predecessor)
|
|||||||
|
Acquisition
costs of properties
|
|||||||
|
Proved
|
$
|
1,425
|
$
|
558
|
|||
|
Unproved
|
3,060
|
55
|
|||||
|
Subtotal
|
4,485
|
613
|
|||||
|
Exploration
costs
|
22,471
|
214
|
|||||
|
Development
costs
|
42,038
|
5,706
|
|||||
|
Total
|
$
|
68,994
|
$
|
6,533
|
|||
|
Company's
share of equity method investees' costs of property acquisition,
exploration and development
|
$
|
56
|
$
|
2,020
|
|||
Results
of operations for oil and natural gas producing activities
|
Successor
|
Predecessor
|
||||||||||||||
|
Year
Ended December 31, 2006
|
Six
Months Ended December 31, 2005
|
Six
Months Ended June 30, 2005
|
Year
Ended December 31, 2004
|
||||||||||||
|
Oil
and natural gas producing revenues
|
|||||||||||||||
|
Third-party
|
$
|
271,751
|
$
|
113,090
|
$
|
21,803
|
$
|
57,572
|
|||||||
|
Affiliate
|
-
|
-
|
81,952
|
190,215
|
|||||||||||
|
Total
Revenues
|
271,751
|
113,090
|
103,755
|
247,787
|
|||||||||||
|
Exploration
expenses, including dry hole
|
-
|
4,317
|
7,440
|
||||||||||||
|
Production
costs
|
47,507
|
22,314
|
22,295
|
40,503
|
|||||||||||
|
Depreciation,
depletion, and amortization
|
105,886
|
40,500
|
30,679
|
81,590
|
|||||||||||
|
Oil
and natural gas impairment
|
-
|
-
|
-
|
202,120
|
|||||||||||
|
Income
(loss) before income taxes
|
118,358
|
50,276
|
46,464
|
(83,866
|
)
|
||||||||||
|
Income
tax provision (benefit)
|
44,621
|
19,155
|
17,656
|
(31,869
|
)
|
||||||||||
|
Results
of continuing operations
|
$
|
73,737
|
$
|
31,121
|
$
|
28,808
|
$
|
(51,997
|
)
|
||||||
|
Results
of discontinued operations
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
7,162
|
|||||||
|
Company's
share of equity method investees' results of operations for producing
activities
|
$
|
227 |
$
|
241
|
$
|
161
|
$
|
324
|
|||||||
The
results of operations for oil and natural gas producing activities exclude
interest charges and general and administrative expenses. Sales are based on
market prices.
Net
Proved and Proved Developed Reserve Summary
The
following table sets forth the Company’s net proved and proved developed
reserves (all within the United States) at December 31, 2006, 2005 and
2004, and the changes in the net proved reserves for each of the three years
in
the period then ended as estimated by the independent petroleum consultants.
During the year ended December 31, 2006 and six months ended December 31, 2005,
other relates to reserves associated with Non-Consent Properties. See Note
2.
During
2004, Calpine revised downward its estimate of continuing proved reserves by
a
total of approximately 58 Bcfe or 12%. Approximately 69% of the total revision
was attributable to the downward revision of Calpine’s estimate of proved
reserves in the South Texas fields due to information received from production
results and drilling activity that occurred during 2004. The remaining 31%
of
the total revision was due to the downward revision of Calpine’s estimate of
proved reserves in California of 17%, Other Onshore of 10% and Gulf of Mexico
of
4%. As a result of the decreases in proved undeveloped reserves, Calpine
recorded a non-cash impairment charge of approximately $202.1 million was
recorded for the year ended December 31, 2004.
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
Natural
gas (Bcf)(1):
|
|||||||
|
Net
proved reserves at January 1, 2004 (Predecessor)
|
455
|
100
|
|||||
|
Revisions
of previous estimates
|
(60
|
)
|
14
|
||||
|
Purchases
in place
|
1
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
17
|
5
|
|||||
|
Sales
in place
|
(2
|
)
|
(115
|
)
|
|||
|
Production
|
(37
|
)
|
(4
|
)
|
|||
|
Net
proved reserves at December 31, 2004 (Predecessor)
|
374
|
-
|
|||||
|
Revisions
of previous estimates
|
(11
|
)
|
-
|
||||
|
Purchases
in place
|
-
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
28
|
-
|
|||||
|
Production
|
(27
|
)
|
-
|
||||
|
Other
(5)
|
(19
|
)
|
-
|
||||
|
Net
proved reserves at December 31, 2005 (Successor) (6)
|
345
|
-
|
|||||
|
Revisions
of previous estimates
|
(10
|
)
|
-
|
||||
|
Purchases
in place
|
4
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
81
|
-
|
|||||
|
Sales
in place
|
-
|
-
|
|||||
|
Production
|
(30
|
)
|
-
|
||||
|
Net
proved reserves at December 31, 2006 (Successor)
|
390
|
-
|
|||||
|
Company's
proportional interest in reserves of investees accounted for by the
equity
method - December 31, 2006 (Successor)
|
5 | - | |||||
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
Natural
gas liquids and crude oil (MBbl)(2)(3)
|
|||||||
|
Net
proved reserves at January 1, 2004 (Predecessor)
|
2,902
|
466
|
|||||
|
Revisions
of previous estimates
|
260
|
(15
|
)
|
||||
|
Purchases
in place
|
3
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
48
|
16
|
|||||
|
Sales
in place
|
(2
|
)
|
(451
|
)
|
|||
|
Production
|
(600
|
)
|
(16
|
)
|
|||
|
Net
proved reserves at December 31, 2004 (Predecessor)
|
2,611
|
-
|
|||||
|
Revisions
of previous estimates
|
153
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
108
|
-
|
|||||
|
Sales
in place
|
(9
|
)
|
-
|
||||
|
Production
|
(360
|
)
|
-
|
||||
|
Other
(5)
|
(22
|
)
|
-
|
||||
|
Net
proved reserves at December 31, 2005 (Successor) (6)
|
2,481
|
-
|
|||||
|
Revisions
of previous estimates
|
424
|
- | |||||
|
Purchases
in place
|
286
|
- | |||||
|
Extensions,
discoveries and other additions
|
315
|
- | |||||
|
Sales
in place
|
-
|
- | |||||
|
Production
|
(576
|
)
|
- | ||||
|
Net
proved reserves at December 31, 2006 (Successor)
|
2,930
|
-
|
|||||
|
Company's
proportional interest in reserves of investees accounted for by the
equity
method - December 31, 2006 (Successor)
|
- | - | |||||
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
Bcfe
(1) equivalents (4)
|
|||||||
|
Net
proved reserves at January 1, 2004 (Predecessor)
|
472
|
103
|
|||||
|
Revisions
of previous estimates
|
(58
|
)
|
14
|
||||
|
Purchases
in place
|
1
|
-
|
|||||
|
Extensions,
discoveries and other additions
|
17
|
5
|
|||||
|
Sales
in place
|
(2
|
)
|
(118
|
)
|
|||
|
Production
|
(41
|
)
|
(4
|
)
|
|||
|
Net
proved reserves at December 31, 2004 (Predecessor)
|
389
|
-
|
|||||
|
Revisions
of previous estimates
|
(10
|
)
|
-
|
||||
|
Extensions,
discoveries and other additions
|
29
|
-
|
|||||
|
Production
|
(30
|
)
|
-
|
||||
|
Other
(5)
|
(19
|
)
|
-
|
||||
|
Net
proved reserves at December 31, 2005 (Successor) (6)
|
359
|
-
|
|||||
|
Revisions
of previous estimates
|
(7
|
)
|
- | ||||
|
Purchases
in place
|
6
|
- | |||||
|
Extensions,
discoveries and other additions
|
83
|
- | |||||
|
Sales
in place
|
-
|
- | |||||
|
Production
|
(33
|
)
|
- | ||||
|
Net
proved reserves at December 31, 2006 (Successor)
|
408
|
-
|
|||||
|
Company's
proportional interest in reserves of investees accounted for by the
equity
method - December 31, 2006 (Successor)
|
5 | - | |||||
Net
proved developed reserves
|
Proved
Developed Reserves
|
||||||||||
|
Natural
gas
(Bcf)
(1)
|
Natural
gas liquids and crude oil (MBbl) (2) (3)
|
Equivalents
Bcfe
(4)
|
||||||||
|
December
31, 2004 (Predecessor)
|
256
|
1,402
|
264
|
|||||||
|
December
31, 2005 (Successor) (6)
|
223
|
1,320
|
231
|
|||||||
|
December
31, 2006 (Successor) (6)
|
251
|
1,965
|
263
|
|||||||
|
(1)
|
Billion
cubic feet or billion cubic feet equivalent, as
applicable
|
|
(2)
|
Thousand
barrels
|
|
(3)
|
Includes
crude oil, condensate and natural gas
liquids
|
|
(4)
|
Natural
gas liquids and crude oil volumes have been converted to equivalent
natural gas volumes using a conversion factor of six cubic feet of
natural
gas to one barrel of natural gas liquids and crude
oil.
|
|
(5)
|
Reserves
associated with Non-Consent
Properties.
|
|
(6)
|
Excludes
reserves associated with Non-Consent
Properties.
|
Standardized
Measure of Discounted Future Net cash Flows Relating to Proved Oil and Natural
Gas Reserves
The
following information has been developed utilizing procedures prescribed by
SFAS
No. 69 and based on natural gas and crude oil reserve and production
volumes estimated by the independent petroleum reservoir engineers. This
information may be useful for certain comparison purposes but should not be
solely relied upon in evaluating the Company or its performance. Further,
information contained in the following table should not be considered as
representative of realistic assessments of future cash flows, nor should the
standardized measure of discounted future net cash flows be viewed as
representative of the current value of the Company’s oil and natural gas
assets.
The
future cash flows presented below are based on sales prices, cost rates and
statutory income tax rates in existence as of the date of the projections.
It is
expected that material revisions to some estimates of natural gas and crude
oil
reserves may occur in the future, development and production of the reserves
may
occur in periods other than those assumed, and actual prices realized and costs
incurred may vary significantly from those used. Income tax expense has been
computed using expected future tax rates and giving effect to tax deductions
and
credits available, under current laws, and which relate to oil and natural
gas
producing activities.
Management
does not rely upon the following information in making investment and operating
decisions. Such decisions are based upon a wide range of factors, including
estimates of probable as well as proved reserves and varying price and cost
assumptions considered more representative of a range of possible economic
conditions that may be anticipated.
The
following table sets forth the standardized measure of discounted future net
cash flows from projected production of the Company’s natural gas and crude oil
reserves for the years ended December 31, 2006, 2005 and 2004.
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
(In
millions)
|
|||||||
|
December
31, 2006 (Successor)
|
|||||||
|
Future
cash inflows
|
$
|
2,452
|
$
|
-
|
|||
|
Future
production costs
|
(684
|
)
|
-
|
||||
|
Future
development costs
|
(312
|
)
|
-
|
||||
|
Future
net cash flows before income taxes
|
1,456
|
-
|
|||||
|
Future
income taxes
|
(182
|
)
|
-
|
||||
|
Future
net cash flows
|
1,274
|
-
|
|||||
|
Discount
to present value at 10% annual rate
|
(552
|
)
|
-
|
||||
|
Standardized
measure of discounted future net cash flows relating to proved natural
gas, natural gas liquids and crude oil reserves
|
$
|
722
|
$
|
-
|
|||
|
Company's
share of equity method investee's standardized measure of discounted
future net cash flows
|
2 |
$
|
-
|
||||
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
(In
millions)
|
|||||||
|
December
31, 2005 (Successor)
|
|||||||
|
Future
cash inflows
|
$
|
3,232
|
$
|
-
|
|||
|
Future
production costs
|
(647
|
)
|
-
|
||||
|
Future
development costs
|
(244
|
)
|
-
|
||||
|
Future
net cash flows before income taxes
|
2,341
|
-
|
|||||
|
Future
income taxes
|
(487
|
)
|
-
|
||||
|
Future
net cash flows
|
1,854
|
-
|
|||||
|
Discount
to present value at 10% annual rate
|
(738
|
)
|
-
|
||||
|
Standardized
measure of discounted future net cash flows relating to proved natural
gas, natural gas liquids and crude oil reserves
|
$
|
1,116
|
$
|
-
|
|||
|
Company's
share of equity method investee's standardized measure of discounted
future net cash flows
|
$
|
2
|
$
|
-
|
|||
|
December
31, 2004 (Predecessor)
|
|||||||
|
Future
cash inflows
|
$
|
2,427
|
$
|
-
|
|||
|
Future
production costs
|
(568
|
)
|
-
|
||||
|
Future
development costs
|
(190
|
)
|
-
|
||||
|
Future
net cash flows before income taxes
|
1,669
|
-
|
|||||
|
Future
income taxes
|
(474
|
)
|
-
|
||||
|
Future
net cash flows
|
1,195
|
-
|
|||||
|
Discount
to present value at 10% annual rate
|
(542
|
)
|
|||||
|
Standardized
measure of discounted future net cash flows relating to proved natural
gas, natural gas liquids and crude oil reserves
|
$
|
653
|
$
|
-
|
|||
|
Company's
share of equity method investee's standardized measure of discounted
future net cash flows
|
$
|
2
|
$
|
-
|
|||
Changes
in Standardized Measure of Discounted Future Net cash
Flows
The
following table sets forth the changes in the standardized measure of discounted
future net cash flows at December 31, 2006, 2005 and 2004.
|
Continued
Operations
|
Discontinued
Operations
|
||||||
|
(In
millions)
|
|||||||
|
Balance,
January 1, 2004 (predecessor)
|
$
|
775
|
$
|
150
|
|||
|
Sales
and transfers of natural gas, natural gas liquids and crude oil produced,
net of production costs
|
(205
|
)
|
(18
|
)
|
|||
|
Net
changes in prices and production costs
|
39
|
2
|
|||||
|
Extensions,
discoveries, additions and improved recovery, net of related
costs
|
60
|
11
|
|||||
|
Development
costs incurred
|
25
|
5
|
|||||
|
Revisions
of previous quantity estimates and development costs
|
(193
|
)
|
10
|
||||
|
Accretion
of discount
|
78
|
15
|
|||||
|
Net
change in income taxes
|
39
|
59
|
|||||
|
Purchases
of reserve in place
|
2
|
-
|
|||||
|
Sales
of reserves in place
|
(5
|
)
|
(208
|
)
|
|||
|
Changes
in timing and other
|
38
|
(26
|
)
|
||||
|
Balance
December 31, 2004 (Predecessor)
|
653
|
-
|
|||||
|
Sales
and transfers of natural gas, natural gas liquids and crude oil produced,
net of production costs
|
(184
|
)
|
-
|
||||
|
Net
changes in prices and production costs
|
526
|
-
|
|||||
|
Extensions,
discoveries, additions and improved recovery, net of related
costs
|
123
|
-
|
|||||
|
Development
costs incurred
|
89
|
-
|
|||||
|
Revisions
of previous quantity estimates and development costs
|
(84
|
)
|
-
|
||||
|
Accretion
of discount
|
74
|
-
|
|||||
|
Net
change in income taxes
|
(55
|
)
|
|||||
|
Changes
in timing and other
|
(26
|
)
|
|||||
|
Balance
December 31, 2005 (Successor) (1)
|
1,116
|
|
-
|
||||
|
Sales
and transfers of natural gas, natural gas liquids and crude oil produced,
net of production costs
|
(224 |
)
|
- | ||||
|
Net
changes in prices and production costs
|
(547 |
)
|
- | ||||
|
Extensions,
discoveries, additions and improved recovery, net of related
costs
|
275 | - | |||||
|
Development
costs incurred
|
73 | - | |||||
|
Revisions
of previous quantity estimates and development costs
|
(348 | ) | - | ||||
|
Accretion
of discount
|
132 | - | |||||
|
Net
change in income taxes
|
132 | - | |||||
|
Purchases
of reserve in place
|
19 | - | |||||
|
Sales
of reserves in place
|
- | - | |||||
|
Changes
in timing and other
|
94 | - | |||||
|
Balance
December 31, 2006 (Successor) (1)
|
$
|
722
|
$
|
-
|
|||
Rosetta
Resources, Inc.
Selected
Data (Unaudited)
Quarterly
Information (Unaudited)
Summaries
of the Company’s results of operations by quarter for the years ended 2006 and
2005 are as follows:
|
Successor
(1)
|
|||||||||||||
|
2006
|
|||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
||||||||||
|
(In
thousands, except per share data)
|
|||||||||||||
|
Revenues
|
$
|
64,544
|
$
|
63,381
|
$
|
71,197
|
$
|
72,641
|
|||||
|
Operating
Income
|
18,452
|
19,438
|
22,530
|
24,717
|
|||||||||
|
Net
Income
|
9,526
|
9,964
|
11,922
|
13,196
|
|||||||||
|
Basic
earnings per share
|
$
|
0.19
|
$
|
0.20
|
$
|
0.24
|
$
|
0.26
|
|||||
|
Diluted
earnings per share
|
$
|
0.19
|
$
|
0.20
|
$
|
0.24
|
$
|
0.26
|
|||||
|
Predecessor
(1)
|
Successor
(1)
|
||||||||||||||
|
2005
|
|||||||||||||||
|
First
Quarter
|
Second
Quarter
|
Third
Quarter
|
Fourth
Quarter
|
||||||||||||
|
(In
thousands, except per share data)
|
|||||||||||||||
|
Revenues
|
$
|
50,555
|
$
|
53,276
|
$
|
57,865
|
$
|
55,239
|
|||||||
|
Operating
Income
|
20,449
|
16,414
|
17,240
|
18,363
|
|||||||||||
|
Net
Income
|
10,662
|
8,019
|
8,207
|
9,328
|
|||||||||||
|
Basic
earnings per share
|
$
|
0.21
|
$
|
0.16
|
$
|
0.16
|
$
|
0.19
|
|||||||
|
Diluted
earnings per share
|
$
|
0.21
|
$
|
0.16
|
$
|
0.16
|
$
|
0.19
|
|||||||
|
(1)
|
Differences
in accounting principles of the predecessor and successor exist and
will
affect the comparability of the data. Differences primarily relate
to the
full cost method of accounting adopted by the Company and the successful
efforts method of accounting followed by the predecessor and differences
in accounting for stock based compensation. See Note
3.
|
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None
Item
9A. Controls and Procedures
Disclosure
Controls and Procedures
Under
the
supervision and with the participation of our management, including our Chief
Executive Officer and Chief Financial Officer, we conducted an evaluation of
the
effectiveness of the design and operation of our disclosure controls and
procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Securities
Exchange Act of 1934, as amended (“Exchange Act”), as of December 31, 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 December 31, 2006, our disclosure controls and procedures
were effective, at the reasonable assurance level, and the material weaknesses
in internal control over financial reporting specifically identified as of
September 30, 2006 and described below have been successfully remediated in
the
fourth quarter of 2006. We believe our audited Consolidated/Combined Financial
Statements included in this annual filing on Form 10-K 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 annual reporting.
In
preparing our Exchange Act filings, including this annual filing on Form 10-K,
we implemented processes and procedures to provide reasonable assurance that
the
identified material weaknesses in our internal control over financial reporting
at September 30, 2006 were remediated in the fourth quarter of 2006 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
the best of their knowledge, that this annual filing on Form 10-K 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 had identified various deficiencies in internal control over
financial reporting. We believe that many of these were attributable to our
transition from a subsidiary of a much larger company to a stand alone entity.
In connection with the preparation of our Consolidated/Combined Financial
Statements and our assessment of the effectiveness of our disclosure controls
and procedures as of December 31, 2006 to be included in this Annual Report
on
Form 10-K to be filed under the Exchange Act, we have remediated the following
specific control deficiencies, which represented material weaknesses in our
internal control over financial reporting as of September 30, 2006:
|
a)
|
Prior
to our effective remediation, we did not have a sufficient complement
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)
|
Prior
to our effective remediation, 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.
|
These
material weaknesses could have resulted in a misstatement of certain
accounts and disclosures which would result in a material misstatement of
interim financial statements that would not be prevented or detected.
Accordingly, management concluded at the time of assessment that these control
deficiencies constituted material weaknesses as of December 31, 2005, March
31,
2006 and June 30, 2006.
Remediation
Activities
As
discussed above, management identified certain material weaknesses that existed
in our internal control over financial reporting and took steps to strengthen
our internal control over financial reporting. Starting in January 2006, we
began hiring additional qualified accounting personnel and completed our
staffing program in the third quarter of 2006. Our documentation of accounting
procedures and key policies was complete at December 31, 2006. Specifically,
the
remedial actions were as follows:
|
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;
|
|
4.
|
We
employed a certified public accountant with top tier Accounting firm
and
industry experience to fill the position of oil and gas property
analyst;
|
|
5.
|
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;
|
|
6.
|
We
employed two supervisory level accountants who have extensive industry
experience;
|
|
7.
|
We
engaged a national tax consulting firm to review our accounting for
certain transactions and disclosures;
and
|
|
8.
|
We
have substantially completed the initial documentation of our internal
accounting procedures, controls and key policies as part of our process
of
compliance as required for the year ended December 31, 2007, pursuant
to
Section 404 of the Sarbanes-Oxley
Act.
|
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 have completed the initial
documentation phase of our control process and will begin testing of our
internal control over financial reporting in the second quarter of 2007 and
will
seek to remediate any additional material weaknesses, if any, identified during
that activity. Furthermore, we believe we have a program in place which will
be
compliant by December 2007 with Section 404 of the Sarbanes-Oxley Act. However,
it is possible we may not be able to complete the required management assessment
or remediation 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.
Item
9B. Other Information
None
PART
III
Item
10.
Directors, Executive Officers and Corporate Governance
The
information required to be contained in this Item is incorporated by reference
from Part I of this report and by reference to our definitive proxy statement
to
be filed with respect to our 2007 annual meeting.
Item
11.
Executive Compensation
The
information required to be contained in this Item is incorporated by reference
to our definitive proxy statement to be filed with respect to our 2007 annual
meeting under the heading “Executive Compensation”.
Item
12. Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder
Matters
This
information required to be contained in this Item is incorporated by reference
to our definitive proxy statement to be filed with respect to our 2007 annual
meeting under the heading “Principal Stockholders and Security Ownership of
Management”.
Item
13. Certain Relationships and Related Transactions, and
Director Independence
The
information required to be contained in this Item is incorporated by reference
to our definitive proxy statement to be filed with respect to our 2007 annual
meeting under the heading “Certain Transactions”.
Item
14. Principal Accountant Fees and
Services
The
information required to be contained in this Item is incorporated by reference
to our definitive proxy statement to be filed with respect to our 2007 annual
meeting.
Item
15. Exhibits and Financial Statement
Schedules
|
(a)
|
The
following documents are filed as a part of this report or incorporated
herein by reference:
|
|
(1)
|
Our
Consolidated/Combined Financial Statements are listed on page 49
of this
report.
|
|
(2)
|
Financial
Statement Schedules:
|
None
92
|
(3)
|
Exhibits:
|
The
following documents are included as exhibits to this report:
|
Exhibit
Number
|
Description
|
|
|
3.1
|
Certificate
of Incorporation (incorporated herein by reference to Exhibit 3.1
to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No. 333-128888)).
|
|
|
3.2
|
Bylaws
(incorporated herein by reference to Exhibit 3.2 to the Company’s
Registration Statement on Form S-1 filed on October 7, 2005 (Registration
No. 333-128888)).
|
|
|
4.1
|
Registration
Rights Agreement (incorporated herein by reference to Exhibit 4.1
to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No. 333-128888)).
|
|
|
10.1
|
Purchase
and Sale Agreement with Calpine Corporation, Calpine Gas Holdings,
L.L.C.
and Calpine Fuels Corporation (incorporated herein by reference to
Exhibit
10.1 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.2
|
Transfer
and Assumption Agreements with Calpine Corporation and Subsidiaries
of
Rosetta Resources Inc. (incorporated herein by reference to Exhibit
10.2
to the Company’s Registration Statement on Form S-1 filed on October 7,
2005 (Registration No. 333-128888)).
|
|
|
10.4
|
Gas
Purchase and Sale Contract with Calpine Energy Services, L.P.
(incorporated herein by reference to Exhibit 10.4 to the Company’s
Registration Statement on Amendment No. 1 to Form S-1 filed on January
3,
2006 (Registration No. 333-128888)).
|
|
|
10.5
|
Services
Agreement with Calpine Producer Services, L.P. (incorporated herein
by
reference to Exhibit 10.5 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.9**
|
2005
Long-Term Incentive Plan (incorporated herein by reference to Exhibit
10.9
to the Company’s Registration Statement on Form S-1 filed on October 7,
2005 (Registration No. 333-128888)).
|
|
|
10.10**
|
Form
of Option Grant Agreement (incorporated herein by reference to Exhibit
10.10 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No.
333-128888)).
|
|
Exhibit
Number
|
Description
|
|
|
10.11**
|
Form
of Restricted Stock Agreement (incorporated herein by reference to
Exhibit
10.11 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.12**
|
Form
of Bonus Restricted Stock Agreement (incorporated herein by reference
to
Exhibit 10.12 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.13**
|
Employment
Agreement with B.A. Berilgen (incorporated herein by reference to
Exhibit
10.13 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.14**
|
Amended
and Restated Employment Agreement with Michael J. Rosinski (incorporated
herein by reference to Exhibit 10.14 to the Company’s Registration
Statement on Form S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.15**
|
Employment
Agreement with Charles F. Chambers (incorporated herein by reference
to
Exhibit 10.15 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.16**
|
Employment
Agreement with Edward E. Seeman (incorporated herein by reference
to
Exhibit 10.16 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.17**
|
Employment
Agreement with Michael H. Hickey (incorporated herein by reference
to
Exhibit 10.17 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.18
|
Senior
Revolving Credit Agreement (incorporated herein by reference to Exhibit
10.18 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.19
|
Second
Lien Term Loan Agreement (incorporated herein by reference to Exhibit
10.19 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.20
|
Guarantee
and Collateral Agreement (incorporated herein by reference to Exhibit
10.20 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.21
|
Second
Lien Guarantee and Collateral Agreement (incorporated herein by reference
to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 filed
on October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.22
|
First
Amendment to Senior Revolving Credit Agreement (incorporated herein
by
reference to Exhibit 10.22 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.23
|
First
Amendment to Second Lien Term Loan Agreement (incorporated herein
by
reference to Exhibit 10.23 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.24
|
First
Amendment to Guarantee and Collateral Agreement (incorporated herein
by
reference to Exhibit 10.24 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
Exhibit
Number
|
Description
|
|
|
10.25
|
First
Amendment to Second Lien Guarantee and Collateral Agreement (incorporated
herein by reference to Exhibit 10.25 to the Company’s Registration
Statement on Form S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.26
|
Deposit
Account Control Agreement (incorporated herein by reference to Exhibit
10.26 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.27**
|
Amendment
No. 1 to B.A. Berilgen Employment Agreement (incorporated herein
by
reference to Exhibit 10.27 to the Company’s Registration Statement on
Amendment No. 1 to Form S-1 filed on January 3, 2006 (Registration
No.
333-128888)).
|
|
|
10.28**
|
First
Amendment to 2005 Long-Term Incentive Plan (incorporated herein by
reference to Exhibit 10.28 to the Company’s Registration Statement on
Amendment No. 1 to Form S-1 filed on January 3, 2006 (Registration
No. 333-128888)).
|
|
|
10.29**
|
Non-Executive
Employee Change of Control Plan (incorporated herein by reference
to
Exhibit 10.29 to the Company’s Registration Statement on Amendment No. 1
to Form S-1 filed on January 3, 2006 (Registration No.
333-128888)).
|
|
|
14.1
|
Code
of Ethics posted on the Company’s website at www.rosettaresources.com.
|
|
|
21.1*
|
Subsidiaries
of the registrant
|
|
|
23.1*
|
Consent
of PricewaterhouseCoopers LLP
|
|
|
23.2*
|
Consent
of PricewaterhouseCoopers LLP
|
|
|
23.3*
|
Consent
of Netherland, Sewell & Associates, Inc.
|
|
|
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.
|
|
*
|
Filed
herewith
|
|
**
|
Management
contract or compensatory plan or arrangement required to be filed
as an
exhibit hereto.
|
Signatures
Pursuant
to the requirements of Section 13 or 15(d) 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, on March 16, 2007.
|
ROSETTA
RESOURCES INC.
|
||
|
By:
|
/s/
B.A. Berilgen
|
|
|
B.A.
Berilgen, Chairman of the Board, President and Chief Executive
Officer
|
||
Pursuant
to the requirements of the Securities Exchange Act of 1933, this report has
been
signed below by the following persons on behalf of the registrant and in the
capacity and on the dates indicated:
|
Signature
|
Title
|
Date
|
||
|
/s/
B. A. Berilgen
|
Chairman
of the Board, President and Chief
|
March
16, 2007
|
||
|
B.
A. Berilgen
|
Executive
Officer (Principal Executive Officer)
|
|||
|
/s/
Michael J. Rosinski
|
March
16, 2007
|
|||
|
Michael
J. Rosinski
|
Executive
Vice President and Chief Financial Officer (Principal Financial
Officer)
|
|||
|
/s/
Denise D. Bednorz
|
Vice
President, Controller
|
March
16, 2007
|
||
|
Denise
D. Bednorz
|
(Principal
Accounting Officer)
|
|||
|
/s/
Richard W. Beckler
|
Director
|
March
16, 2007
|
||
|
Richard
W. Beckler
|
||||
|
/s/
Donald D. Patteson, Jr.
|
Director
|
March
16, 2007
|
||
|
Donald
D. Patteson, Jr.
|
||||
|
/s/
D. Henry Houston
|
Director
|
March
16, 2007
|
||
|
D.
Henry Houston
|
||||
|
/s/
G. Louis Graziadio, III
|
Director
|
March
16, 2007
|
||
|
G.
Louis Graziadio, III
|
||||
|
/s/
Josiah O. Low, III
|
Director
|
March
16, 2007
|
||
|
Josiah
O. Low, III
|
Glossary
of Oil and Natural Gas Terms
We
are in
the business of exploring for and producing oil and natural gas. Oil and gas
exploration is a specialized industry. Many of the terms used to describe our
business are unique to the oil and natural gas industry. The following is a
description of the meanings of some of the oil and natural gas industry terms
used in this report.
3-D
Seismic.
(Three-Dimensional Seismic Data) Geophysical data that depicts the subsurface
strata in three dimensions. 3-D seismic data typically provides a more detailed
and accurate interpretation of the subsurface strata than two-dimensional
seismic data.
Amplitude.
The
difference between the maximum displacement of a seismic wave and the point
of
no displacement, or the null point.
(Amplitude
plays) anomalies.
An
abrupt increase in seismic amplitude that can in some instances indicate the
presence of hydrocarbons.
Anticline.
An
arch-shaped fold in rock in which layers are upwardly convex, often forming
a
hydrocarbon trap. Anticlines may form hydrocarbon traps, particularly in folds
with reservoir-quality rocks in their core and impermeable seals in the outer
layers of the fold.
Appraisal
well.
A well
drilled several spacing locations away from a producing well to determine the
boundaries or extent of a productive formation and to establish the existence
of
additional reserves.
Bbl.
One
stock tank barrel, or 42 U.S. gallons liquid volume, of oil or other liquid
hydrocarbons.
Bcf.
Billion
cubic feet of natural gas.
Bcfe.
Billion
cubic feet equivalent determined using the ratio of six Mcf of natural gas
to
one Bbl of crude oil, condensate or natural gas liquids.
Behind
Pipe Pays.
Reserves expected to be recovered from zones in existing wells, which will
require additional completion work or future recompletion prior to the start
of
production.
Block.
A block
depicted on the Outer Continental Shelf Leasing and Official Protraction
Diagrams issued by the U.S. Minerals Management Service or a similar depiction
on official protraction or similar diagrams, issued by a state bordering on
the
Gulf of Mexico.
Btu
or British thermal unit.
The
quantity of heat required to raise the temperature of one pound of water by
one
degree Fahrenheit.
Coalbed
methane.
Coal is
a carbon-rich sedimentary rock that forms from the remains of plants deposited
as peat in swampy environments. Natural gas associated with coal, called coal
gas or coalbed methane, can be produced economically from coal beds in some
areas.
Completion.
The
installation of permanent equipment for the production of oil or natural gas.
Developed
acreage.
The
number of acres that are allocated or assignable to productive wells or wells
capable of production.
Development
well.
A well
drilled within the proved boundaries of an oil or natural gas reservoir with
the
intention of completing the stratigraphic horizon known to be productive.
Dry
hole.
A well
found to be incapable of producing hydrocarbons in sufficient quantities such
that proceeds from the sale of such production exceeds production expenses
and
taxes.
Dry
hole costs.
Costs
incurred in drilling a well, assuming a well is not successful, including
plugging and abandonment costs.
Exploratory
well.
A well
drilled to find and produce oil or natural gas reserves not classified as
proved, to find a new reservoir in a field previously found to be productive
of
oil or natural gas in another reservoir or to extend a known reservoir.
Farmout.
An
agreement
whereby the owner of a leasehold or working interest agrees to assign an
interest in certain specific acreage to the assignees, retaining an interest
such as an overriding royalty interest, an oil and gas payment, offset acreage
or other type of interest, subject to the drilling of one or more specific
wells
or other performance as a condition of the assignment
Fault.
A break
or planar surface in brittle rock across which there is observable displacement.
Faulted
downthrown rollover anticline.
An
arch-shaped fold in rock in which the convex geological structure is tipped
as
opposed to perpendicular to the ground and in which a visible break or
displacement has occurred in brittle rock, often forming a hydrocarbon trap.
Field.
An area
consisting of either a single reservoir or multiple reservoirs all grouped
on or
related to the same individual geological structural feature and/or
stratigraphic condition.
Finding
and development costs.
Capital
costs incurred in the acquisition, exploration, development and revisions of
proved oil and natural gas reserves divided by proved reserve additions.
Fracing
or fracture stimulation technology.
The
technique of improving a well’s production or injection rates by pumping a
mixture of fluids into the formation and rupturing the rock, creating an
artificial channel. As part of this technique, sand or other material may also
be injected into the formation to keep the channel open, so that fluids or
natural gases may more easily flow through the formation.
Gross
acres or gross wells. The
total
acres or wells, as the case may be, in which a working interest is owned.
Horizontal
drilling.
A
drilling operation in which a portion of the well is drilled horizontally within
a productive or potentially productive formation. This operation usually yields
a well that has the ability to produce higher volumes than a vertical well
drilled in the same formation.
Hydrocarbon
indicator.
A type
of seismic amplitude anomaly, seismic event, or characteristic of seismic data
that can occur in a hydrocarbon-bearing reservoir.
Infill
well. A
well
drilled between known producing wells to better exploit the reservoir.
Injection
well or injection. A
well
which is used to place liquids or natural gases into the producing zone during
secondary/tertiary recovery operations to assist in maintaining reservoir
pressure and enhancing recoveries from the field.
Lease
operating expenses. The
expenses of lifting oil or natural gas from a producing formation to the
surface, constituting part of the current operating expenses of a working
interest, and also including labor, superintendence, supplies, repairs,
short-lived assets, maintenance, allocated overhead costs, workover, ad valorem
taxes, insurance and other expenses incidental to production, but excluding
lease acquisition or drilling or completion expenses.
MBbls.
Thousand
barrels of crude oil or other liquid hydrocarbons.
Mcf.
Thousand
cubic feet of natural gas.
Mcfe.
Thousand
cubic feet equivalent determined using the ratio of six Mcf of natural gas
to
one Bbl of oil, condensate or natural gas liquids.
MMBbls.
Million
barrels of oil or other liquid hydrocarbons.
MMBtu.
Million
British Thermal Units.
MMcf.
Million
cubic feet of natural gas.
MMcfe.
Million
cubic feet equivalent determined using the ratio of six Mcf of natural gas
to
one Bbl of oil, condensate or natural gas liquids.
Net
acres or net wells. The
sum
of the fractional working interests owned in gross acres or wells, as the case
may be.
Net
revenue interest.
An
interest in all oil and natural gas produced and saved from, or attributable
to,
a particular property, net of all royalties, overriding royalties, net profits
interests, carried interests, reversionary interests and any other burdens
to
which the person’s interest is subject.
Nonoperated
working interests.
The
working interest or fraction thereof in a lease or unit, the owner of which
is
without operating rights by reason of an operating agreement.
NYMEX.
New York
Mercantile Exchange.
OCS
block. Outer
continental shelf block located outside the state territorial limit.
Operated
working interests. Where
the
working interests for a property are co-owned, and where more than one party
elects to participate in the development of a lease or unit, there is an
operator designated “for full control of all operations within the limits of the
operating agreement” for the development and production of the wells on the
co-owned interests. The working interests of the operating party become the
“operated working interests.”
Payout.
Generally refers to the recovery by the incurring party of its costs of
drilling, completing, equipping and operating a well before another party’s
participation in the benefits of the well commences or is increased to a new
level.
Permeability.
The
ability, or measurement of a rock’s ability, to transmit fluids, typically
measured in darcies or millidarcies. Formations that transmit fluids readily
are
described as permeable and tend to have many large, well-connected pores.
Porosity.
The
percentage of pore volume or void space, or that volume within rock that can
contain fluids.
PV-10
or present value of estimated future net revenues. An
estimate of the present value of the estimated future net revenues from proved
oil and natural gas reserves at a date indicated after deducting estimated
production and ad valorem taxes, future capital costs and operating expenses,
but before deducting any estimates of federal income taxes. The estimated future
net revenues are discounted at an annual rate of 10%, in accordance with the
Securities and Exchange Commission’s practice, to determine their “present
value.” The present value is shown to indicate the effect of time on the value
of the revenue stream and should not be construed as being the fair market
value
of the properties. Estimates of future net revenues are made using oil and
natural gas prices and operating costs at the date indicated and held constant
for the life of the reserves.
Productive
well.
A well
that is found to be capable of producing hydrocarbons in sufficient quantities
such that proceeds from the sale of such production exceed production expenses
and taxes.
Progradation.
The
accumulation of sequences by deposition in which beds are deposited successively
basinward because sediment supply exceeds accommodation.
Prospect.
A
specific geographic area which, based on supporting geological, geophysical
or
other data and also preliminary economic analysis using reasonably anticipated
prices and costs, is deemed to have potential for the discovery of commercial
hydrocarbons.
Proved
developed non-producing reserves.
Proved
developed reserves expected to be recovered from zones behind casing in existing
wells. See Rule 4-10(a), paragraph (2) through (2)iii for a more complete
definition.
Proved
developed producing reserves.
Proved
developed reserves that are expected to be recovered from completion intervals
currently open in existing wells and capable of production to market. See Rule
4-10(a), paragraph (2) through (2)iii for a more complete definition.
Proved
developed reserves.
Proved
reserves that can be expected to be recovered from existing wells with existing
equipment and operating methods. See Rule 4-10(a), paragraph (3) for a more
complete definition.
Proved
reserves. The
estimated quantities of oil, natural gas and natural gas liquids that geological
and engineering data demonstrate with reasonable certainty to be recoverable
in
future years from known reservoirs under existing economic and operating
conditions. See Rule 4-10(a), paragraph (2) through (2)iii for a more
complete definition.
Proved
undeveloped reserves.
Proved
reserves that are expected to be recovered from new wells on undrilled acreage
or from existing wells where a relatively major expenditure is required for
recompletion. See Rule 4-10(a), paragraph (4) for a more complete
definition.
Reserve
life index.
This
index is calculated by dividing year-end reserves by the average production
during the past year to estimate the number of years of remaining production.
Reservoir.
A porous
and permeable underground formation containing a natural accumulation of
producible oil and/or natural gas that is confined by impermeable rock or water
barriers and is individual and separate from other reservoirs.
Resistivity.
The
ability of a material to resist electrical conduction. Resistivity is used
to
indicate the presence of water and /or hydrocarbons.
Secondary
recovery.
An
artificial method or process used to restore or increase production from a
reservoir after the primary production by the natural producing mechanism and
reservoir pressure has experienced partial depletion. Natural gas injection
and
waterflooding are examples of this technique.
Shelf.
Areas in
the Gulf of Mexico with depths less than 1,300 feet. Our shelf area and
operations also includes a small amount of properties and operations in the
onshore and bay areas of the Gulf Coast.
Stratigraphy.
The
study of the history, composition, relative ages and distribution of layers
of
the earth’s crust.
Stratigraphic
trap. A
sealed
geologic container capable of retaining hydrocarbons that was formed by changes
in rock type or pinch-outs, unconformities, or sedimentary features such as
reefs.
Tcf.
Trillion
cubic feet of natural gas.
Tcfe.
Trillion
cubic feet equivalent determined using the ratio of six Mcf of natural gas
to
one Bbl of oil, condensate or natural gas liquids.
Trap.
A
configuration of rocks suitable for containing hydrocarbons and sealed by a
relatively impermeable formation through which hydrocarbons will not escape.
Undeveloped
acreage.
Lease
acreage on which wells have not been drilled or completed to a point that would
permit the production of commercial quantities of oil or natural gas regardless
of whether or not such acreage contains proved reserves.
Waterflooding.
A
secondary recovery operation in which water is injected into the producing
formation in order to maintain reservoir pressure and force oil toward and
into
the producing wells.
Working
interest.
The
operating interest that gives the owner the right to drill, produce and conduct
operating activities on the property and receive a share of production.
Workover.
The
repair or stimulation of an existing production well for the purpose of
restoring, prolonging or enhancing the production of hydrocarbons.
Workover
rig.
A
portable rig used to repair or adjust downhole equipment on an existing well.
/d.“Per
day”
when used with volumetric units or dollars.
Index
to Exhibits
|
Exhibit
Number
|
Description
|
||
|
3.1
|
Certificate
of Incorporation (incorporated herein by reference to Exhibit 3.1
to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No. 333-128888)).
|
||
|
3.2
|
|
Bylaws
(incorporated herein by reference to Exhibit 3.2 to the Company’s
Registration Statement on Form S-1 filed on October 7, 2005 (Registration
No. 333-128888)).
|
|
|
4.1
|
Registration
Rights Agreement (incorporated herein by reference to Exhibit 4.1
to the
Company’s Registration Statement on Form S-1 filed on October 7, 2005
(Registration No. 333-128888)).
|
||
|
10.1
|
Purchase
and Sale Agreement with Calpine Corporation, Calpine Gas Holdings,
L.L.C.
and Calpine Fuels Corporation (incorporated herein by reference to
Exhibit
10.1 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
||
|
|
|||
|
10.2
|
|
Transfer
and Assumption Agreements with Calpine Corporation and Subsidiaries
of
Rosetta Resources Inc. (incorporated herein by reference to Exhibit
10.2
to the Company’s Registration Statement on Form S-1 filed on October 7,
2005 (Registration No. 333-128888)).
|
|
|
|
|
||
|
10.4
|
Gas
Purchase and Sale Contract with Calpine Energy Services, L.P.
(incorporated herein by reference to Exhibit 10.4 to the Company’s
Registration Statement on Amendment No. 1 to Form S-1 filed on January
3,
2006 (Registration No. 333-128888)).
|
||
|
10.5
|
Services
Agreement with Calpine Producer Services, L.P. (incorporated herein
by
reference to Exhibit 10.5 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
||
|
10.9**
|
2005
Long-Term Incentive Plan (incorporated herein by reference to Exhibit
10.9
to the Company’s Registration Statement on Form S-1 filed on October 7,
2005 (Registration No. 333-128888)).
|
||
|
|
|||
|
10.10**
|
|
Form
of Option Grant Agreement (incorporated herein by reference to Exhibit
10.10 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.11**
|
Form
of Restricted Stock Agreement (incorporated herein by reference to
Exhibit
10.11 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No.
333-128888)).
|
||
|
Exhibit
Number
|
Description
|
|
|
10.12**
|
Form
of Bonus Restricted Stock Agreement (incorporated herein by reference
to
Exhibit 10.12 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.13**
|
Employment
Agreement with B.A. Berilgen (incorporated herein by reference to
Exhibit
10.13 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.14**
|
Amended
and Restated Employment Agreement with Michael J. Rosinski (incorporated
herein by reference to Exhibit 10.14 to the Company’s Registration
Statement on Form S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.15**
|
Employment
Agreement with Charles F. Chambers (incorporated herein by reference
to
Exhibit 10.15 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
|
||
|
10.16**
|
Employment
Agreement with Edward E. Seeman (incorporated herein by reference
to
Exhibit 10.16 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
|
||
|
10.17**
|
Employment
Agreement with Michael H. Hickey (incorporated herein by reference
to
Exhibit 10.17 to the Company’s Registration Statement on Form S-1 filed on
October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.18
|
Senior
Revolving Credit Agreement (incorporated herein by reference to Exhibit
10.18 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
|
||
|
10.19
|
|
Second
Lien Term Loan Agreement (incorporated herein by reference to Exhibit
10.19 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
10.20
|
Guarantee
and Collateral Agreement (incorporated herein by reference to Exhibit
10.20 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.21
|
Second
Lien Guarantee and Collateral Agreement (incorporated herein by reference
to Exhibit 10.21 to the Company’s Registration Statement on Form S-1 filed
on October 7, 2005 (Registration No. 333-128888)).
|
|
|
10.22
|
First
Amendment to Senior Revolving Credit Agreement (incorporated herein
by
reference to Exhibit 10.22 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.23
|
First
Amendment to Second Lien Term Loan Agreement (incorporated herein
by
reference to Exhibit 10.23 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.24
|
First
Amendment to Guarantee and Collateral Agreement (incorporated herein
by
reference to Exhibit 10.24 to the Company’s Registration Statement on Form
S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
|
10.25
|
First
Amendment to Second Lien Guarantee and Collateral Agreement (incorporated
herein by reference to Exhibit 10.25 to the Company’s Registration
Statement on Form S-1 filed on October 7, 2005 (Registration No.
333-128888)).
|
|
Exhibit
Number
|
Description
|
|
|
10.26
|
Deposit
Account Control Agreement (incorporated herein by reference to Exhibit
10.26 to the Company’s Registration Statement on Form S-1 filed on October
7, 2005 (Registration No. 333-128888)).
|
|
|
10.27**
|
Amendment
No. 1 to B.A. Berilgen Employment Agreement (incorporated herein
by
reference to Exhibit 10.27 to the Company’s Registration Statement on
Amendment No. 1 to Form S-1 filed on January 3, 2006 (Registration
No.
333-128888)).
|
|
|
10.28**
|
First
Amendment to 2005 Long-Term Incentive Plan (incorporated herein by
reference to Exhibit 10.28 to the Company’s Registration Statement on
Amendment No. 1 to Form S-1 filed on January 3, 2006 (Registration
No.
333-128888)).
|
|
|
10.29**
|
Non-Executive
Employee Change of Control Plan (incorporated herein by reference
to
Exhibit 10.29 to the Company’s Registration Statement on Amendment No. 1
to Form S-1 filed on January 3, 2006 (Registration No.
333-128888)).
|
|
|
14.1
|
Code
of Ethics posted on the Company’s website at www.rosettaresources.com.
|
|
|
Subsidiaries
of the registrant
|
||
|
Consent
of PricewaterhouseCoopers LLP
|
||
|
Consent
of PricewaterhouseCoopers LLP
|
||
|
Consent
of Netherland, Sewell & Associates, Inc.
|
||
|
|
||
|
Certification
of Periodic Financial Reports by B.A. Berilgen in satisfaction of
Section
302 of the Sarbanes-Oxley Act of 2002.
|
||
|
Certification
of Periodic Financial Reports by Michael J. Rosinski in satisfaction
of
Section 302 of the Sarbanes-Oxley Act of 2002.
|
||
|
Certification
of Periodic Financial Reports by B.A. Berilgen and Michael J. Rosinski
in
satisfaction of Section 906 of the Sarbanes-Oxley Act of
2002.
|
* Filed
herewith
** Management
contract or compensatory plan or arrangement required to be filed as an exhibit
hereto.
103