form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
S
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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, 2007
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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The
Nasdaq Stock Market LLC
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Common
Stock, $.001 Par Value
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(Nasdaq
Global Select Market)
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(Title
of Class)
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(Name
of Exchange on which registered)
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Securities
Registered 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 Exchange Act. Yes S
No £
Indicate
by check mark if the Registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Exchange Act. Yes £ No
S
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 S 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. S
Indicate
by check mark whether the Registrant is a large accelerated filer, an
accelerated filer, a non-accelerated filer or a smaller reporting
company. See the definitions of “large accelerated filer,”
“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the
Exchange Act.
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Large accelerated
filer S
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Accelerated filer
£
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Non-Accelerated
filer £
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Smaller Reporting
Company £
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(Do
not check if smaller reporting company)
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Indicate
by check mark whether the Registrant is a shell company (as defined by Rule
12b-2 of the Exchange Act). Yes £ No S
The
aggregate market value of the voting and non-voting common equity held by
Non-affiliates of the registrant as of June 29, 2007 was approximately $1.1
billion based on the closing price of $21.54 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 February 18, 2008 was 51,146,322.
Documents
Incorporated By Reference
Information
required by Part III will either be included in Rosetta Resources Inc.
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.
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 95.
Part
I
General
We are an
independent oil and gas company engaged in the acquisition, exploration,
development and production of oil and gas properties in North
America. Our operations are concentrated in the Sacramento Basin of
California, the Rocky Mountains, the Lobo and Perdido trends in South Texas, the
State Waters of Texas and the Gulf of Mexico. We are a Delaware
corporation based in Houston, Texas.
Rosetta
Resources Inc. (together with our consolidated subsidiaries, the “Company”) was
formed in June 2005 to acquire Calpine Natural Gas L.P., its partners and the
domestic oil and natural gas business formerly owned by Calpine Corporation and
its affiliates (“Calpine”). We (“Successor”) acquired Calpine Natural
Gas L.P. and its partners (“Predecessor”) and Rosetta Resources California, LLC,
Rosetta Resources Rockies, LLC, Rosetta Resources Offshore, LLC and Rosetta
Resources Texas LP and its partners, in July 2005 (hereinafter, the
“Acquisition”). We have subsequently acquired numerous other oil and
natural gas properties, and we are engaged in oil and natural gas exploration,
development, production and acquisition activities in the United
States. We operate in one business segment. See Note 15 to
our consolidated/combined financial statements. We have grown our
existing property base by developing and exploring our acreage; purchasing new
undeveloped leases; acquiring oil and gas producing properties and drilling
prospects from third parties.
Pursuant
to the Acquisition, we entered into several operative contracts with Calpine,
including a purchase and sale agreement and all interrelated agreements,
concurrently executed on or about July 7, 2005 (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 original term ran through June 30, 2007. In
connection with the partial transfer and release agreement executed by Calpine
and the Company on August 3, 2007 (the “PTRA”), a new marketing agreement was
entered into whose term is from July 1, 2007 through June 30, 2009, subject to
earlier termination on certain events. 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 Purchase Agreement. The PTRA and
gas purchase and sales contracts with Calpine are discussed further under Part
I. Item 3. Legal Proceedings.
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, the Rocky
Mountains, South Texas, the State Waters of Texas and the Gulf of Mexico. 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. We also believe our
current asset base provides a strong platform for additional
acquisitions.
Development and
Exploration Drilling Inventory. We have identified an inventory
of low to moderate risk opportunities providing us with multiple
years of drilling, and we expect to drill approximately 190 of these
locations during 2008. Approximately 20% of these locations are classified
as proved undeveloped. We also
believe we have access to a large and diversified portfolio of non-proved
resource inventory that will drive future growth. Our capital
expenditure budget is $290.1 million for 2008. 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 88% 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, New Leadership. Our executive management team
has an average of 29 years of experience in the energy industry with specific
experience in the areas where our primary properties are located. In
November 2007, Randy L. Limbacher became our President and Chief Executive
Officer (“CEO”) replacing B. A. Berilgen who resigned in 2007. Mr.
Limbacher personally has 27 years of experience in the energy industry, most
recently serving as President, Exploration and Production - Americas
for ConocoPhillips.
Proven Technical
and Land Personnel with Access to Technological Resources. Our technical
staff includes 36 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 complex basins and managing coalbed methane operations. These core
competencies helped us to achieve a drilling success rate of 82% for the year
ended December 31, 2007 and has helped maximize recovery from our
reservoirs. Our definition of drilling success is a well that is producing or
capable of production, including natural gas wells awaiting pipeline connections
to commence deliveries and oil wells awaiting connection to production
facilities. Previously, our definition of a successful well was a
well that produced hydrocarbons at sufficient rates to allow us to recover, at a
minimum, our capital investment and operating costs. Under the
previous definition, our success rate would have been 72%.
Our
Strategy
Our
strategy is to increase stockholder value by managing our reserves, production,
cash flow and profitability using a balanced program of (1) developing and
extending inventory in existing core properties, (2) establishing new
resource based core areas, (3) exploitation and exploration activities, (4)
completing acquisitions and selective divestitures, (5) maintaining
technical expertise, (6) focusing on cost control and (7) maintaining financial
flexibility. We will seek to accomplish these goals while
working to protect stockholders interests by focusing on sustainability,
spending our various resources wisely, monitoring emerging trends, minimizing
liabilities through governmental compliance, respecting the dignity of human
life, and protecting the environment. The following are key elements
of our strategy:
Developing and
Extending Existing Core Properties. We have designated the Sacramento
Basin, the DJ Basin and South Texas as core areas and intend to build our asset
base in these areas through additional leasing and acquisitions where
applicable. We intend to further develop the upside potential of
these core properties by working over existing wells, drilling in-fill
locations, drilling step-out wells to expand known field outlines, recompleting
to logged behind pipe pays and lowering field line pressures through compression
for additional reserve recovery.
Establishing New
Resource Based Core Areas. We intend to extend our presence
into new core areas within North America that are characterized by significant
presence of resource potential that can be exploited utilizing our technological
expertise.
Exploitation and Exploration
Activities. We intend to generate growth in existing and new
core areas in which we have technological and operational advantages by
identifying exploitation and exploration opportunities that contain the
potential to establish repeatable drilling programs.
Completing
Acquisitions and Selective Divestitures. We continually review
opportunities to optimize our portfolio to create stockholder
value. We actively evaluate possible acquisitions of producing
properties, undeveloped acreage and drilling prospects in our existing core
areas, as well as areas where we believe we can establish new core areas by
implementing an “acquire and exploit” strategy. We will focus on
opportunities where we believe our reservoir management and operational
expertise will enhance the value and performance of the acquired properties
through development and exploration based on repeatable drilling
programs. Periodically, we also evaluate possible divestitures of
properties that we believe have limited future potential or that do not fit our
risk profile.
Maintaining
Technological Expertise. We intend to maintain and further develop the
technological expertise that helped us achieve a drilling success rate of 82%
for the year ended December 31, 2007 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.
Focusing on Cost
Control. We will manage all elements of our cost structure including
drilling and operating costs as well as overhead costs. We will strive to
minimize our drilling and operating costs by concentrating our assets within
existing and new sustainable resource based core areas.
Maintaining
Financial Flexibility. We may optimize unused borrowing capacity under
our revolving line of credit by refinancing our bank debt in the capital markets
if conditions are favorable. As of December 31, 2007, we had $179.0 million
available for borrowing under our revolving line of credit, with $170.0 million
drawn 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 continue 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 for a significant
portion of our expected production through 2009. We also entered into a series
of interest rate swap agreements to hedge the change in variable interest rates
associated with our debt under our credit facility through June
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”).
On June
29, 2006, Calpine filed a motion pursuant to Bankruptcy Code Section 365 in
connection with its bankruptcy proceedings and received an order from the
Bankruptcy Court approving Calpine’s precautionary assumption of certain oil and
gas leases which Calpine had previously sold or agreed to sell to us in the
Acquisition, to the extent that the leases both constituted “unexpired leases of
non-residential real property” and were not fully transferred to us at the time
of Calpine’s filing for bankruptcy, in order to prevent Section 365’s “deemed
rejection” of such leases. 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
asked to take further action or pay further consideration to complete the
assignments of these interests or alternatively, Calpine might seek to 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.
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 all of which are covered, we
believe, by the further assurances provision of the Purchase Agreement; however,
the exact details of each property involved and how, when and if this will be
able to be secured or accomplished continue to remain uncertain pending
conclusion of the adversary proceeding Calpine filed against us on June 29,
2007.
Any
failure by Calpine to complete the corrective action necessary to remove title
deficiencies with respect to these various properties, including a 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 business, results of operations, financial condition or
cash flows 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.
On August
1, 2006, we filed proofs of claim in the Calpine bankruptcy asserting claims
against a variety of Calpine debtors seeking recovery of $27.9 million in
liquidated amounts, as well as unliquidated damages in amounts that have not
presently been determined.
On June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court (the “Lawsuit”) alleging that the Acquisition was a fraudulent conveyance
and seeking to recover either the difference between the amounts it received in
the transaction and the reasonably equivalent value of the business conveyed to
us or the return of the business we acquired. We have answered and filed
affirmative counterclaims against Calpine related to the Acquisition for (i)
breach of covenant of solvency, (ii) fraud and fraud in a real estate
transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi)
setoff. The parties have engaged in an active motion practice in relation to
these claims and counterclaims pertaining to the alleged fraudulent conveyance
and discovery continues.
On
September 11, 2007, the Bankruptcy Court approved the Partial Transfer and
Release Agreement ("PTRA") that was executed by Calpine and the
Company on August 3, 2007. Under the PTRA, Calpine resolved any title
issues in order to allow us to have clear legal title in all offshore
properties, certain properties for which the State of California was the lessor,
and certain other properties involved in the Acquisition, without prejudice to
Calpine’s claims and our counterclaims in the pending adversary
proceeding. The PTRA did not include all properties that may have
legal title issues, such as those properties that required non-governmental,
third-party consents or waivers of preferential rights in order to place legal
title of the assets in Rosetta’s name.
On
December 19, 2007, the Bankruptcy Court approved Calpine’s plan of
reorganization (“Plan of Reorganization”). Calpine declared January
31, 2008 as the “effective date” for consummation of its Plan of Reorganization
and it is the date on which Calpine and certain of its subsidiaries emerged from
bankruptcy.
We are
continuing to vigorously defend and affirmatively assert our claims in
connection with the meritless Lawsuit filed by Calpine.
See Item
3. Legal Proceedings for further information regarding the Calpine bankruptcy,
PTRA, and the Lawsuit.
Our
Operating Areas
We own
producing and non-producing oil and natural gas properties in the Sacramento
Basin of California, the Rocky Mountains, the Lobo and Perdido Trends in South
Texas, the State Waters of Texas, the Gulf of Mexico, 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, 2007, we have drilled 195 gross and 169 net
wells, with a success rate of 82%. 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 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 and to certain
properties for which we believe Calpine is obligated to provide further
assurances. See Item 3. Legal Proceedings for further information
regarding the Calpine bankruptcy.
California-Sacramento
Basin
Historically,
the Sacramento Basin is one of California’s most prolific gas producing areas,
containing a majority of the state’s largest gas fields. It is
conveniently located near the Northern California natural gas markets and has a
very robust natural gas gathering and pipeline infrastructure. We are
one of the largest producers and leaseholders in the basin.
As of
December 31, 2007, we owned approximately 76,000 net acres in the Rio Vista
Field and Sacramento Basin areas. Our acreage in the basin holds
significant low-risk, low-cost upside potential, and numerous workover and
recompletion opportunities. Additional reserve potential exists in
gathering system optimization projects, fracture stimulation opportunities in
lower permeability, low contrast pays, and deeper gas bearing
sands.
For the
year ended December 31, 2007, our average net daily production from the Rio
Vista Field and surrounding fields in the Sacramento Basin was 44.0
MMcfe/d. In 2007, we drilled 27 gross wells of which 23 were
successful. We plan to participate in the drilling of 29 wells
in 2008.
Rio Vista Field. The Rio
Vista Gas Unit and a significant portion of the deep rights below the Rio Vista
Gas Unit, which 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 14 different zones at depths ranging
from 2,000 feet to 11,000 feet in the field. The Rio Vista Field trap is a
faulted, downthrown rollover anticline, elongated to the northwest. The current
productive area is approximately ten miles long and nine miles wide. For the
year ended December 31, 2007, the average net daily production in the Rio
Vista Field was approximately 40.5 MMcfe/d. We drilled 23 wells in the Rio
Vista field in 2007; 20 of these were successful. Six wells
drilled in the southern portion of the field were successful in extending areas
in two reservoirs, the Lower Capay and the Martinez. This drilling
effort was supported by a 12 square mile 3-D seismic program that was shot over
the Bradford Island area of the field at the end of 2006. This area
of the field had never been covered by 3-D seismic data.
At
December 31, 2007, we had one deep rig actively drilling in the field. We
secured a second rig at the end of January 2008. We will be procuring
a deep rig during the year to drill a deep test under the City of Rio
Vista. We plan to participate in the drilling of 20 additional wells
in the Rio Vista field in 2008. There are two completion rigs currently working
on Rosetta wells in the Rio Vista area. We plan to utilize two to
three completion rigs throughout the year. In addition, we plan to
conduct between 30 and 40 workover, recompletion or reactivation operations on
field wells with these rigs during 2008.
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 Forbes
stratigraphic traps on the North side of the Sacramento Basin. Subtle 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 550 square miles of 3-D seismic data and over 1,800 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.
We
drilled four wells in the Sacramento Valley Extension area in 2007, three of
these were successful and one was pending completion at year
end. Average daily net production for the year ended December 31,
2007 was 3.5 MMcfe/d. We plan to participate in the drilling of
9 additional wells in the Sacramento Valley Extension area in 2008.
Other
Activities. We are actively pursuing additional lease and
producing property acquisitions throughout the Sacramento Basin. In April 2007,
we acquired properties located in the Sacramento Basin from Output Exploration,
LLC and OPEX Energy, LLC at a total purchase price of $38.7 million (“OPEX
Properties”). The acquisition consisted of 18 producing wells, with
net daily production of 3.1 MMcfe/d, and 9.8 BCF of net reserves. We
also acquired 4,470 net acres, 112 square miles of 3D seismic and several
exploratory prospects in the transaction. The 2008 drilling activity
planned for the Sacramento Valley Extension includes five wells that are related
to the OPEX Properties, either through our added OPEX acreage or our adjoining
acreage, where the improved seismic gained in the OPEX acquisition has helped us
identify additional prospects.
Rocky
Mountains
At
December 31, 2007, we owned approximately 172,000 net acres in the Rocky
Mountains. Our production is concentrated in two basins, the DJ and
the San Juan Basins. Our average net daily production for the year
ended December 31, 2007 was 6.0 MMcfe/d. In 2007, we drilled 89 gross
wells of which 75 were successful.
DJ Basin, Colorado. As of
December 31, 2007, we had a majority working interest in approximately
109,451 net acres with 125 square miles of 3D seismic data. In 2007,
we drilled 70 locations, of which 55 were successful, and identified 49
additional drillable, 3-D seismic supported locations on these
lands. To date as of December 31, 2007, we have drilled 134 wells in
the developed area of which 114 were successful. For the year ended
December 31, 2007, our average net daily production from the DJ Basin was 5.2
MMcfe/d. We have identified over 100 potential drilling locations on our acreage
and plan to participate in the drilling of 60 additional wells in 2008 and
acquire approximately 29 square miles of additional 3-D seismic
data. Pipeline and gathering system construction is expanding in
the Republican River, Vernon, SW Wray and Sandy Bluff areas.
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 Bed Methane
(“CBM”). There is CBM production from depths of 1,600 feet surrounding our
leasehold. As of December 31, 2007, we had a 100% working interest position
in approximately 12,000 net acres. In 2007, we drilled 19 CBM wells and one
saltwater disposal well with all being successful. For the year ended
December 31, 2007, our average net daily production from the San Juan Basin was
0.6 MMcfe/d. We have identified 22 drillable locations on
our acreage and plan to participate in the drilling of 14 wells in
2008.
Lobo
Lobo Trend. We are
a significant producer in the South Texas, Lobo Trend, with approximately 78,000
net acres, 320 square miles of 3-D seismic and approximately 298 operated
producing wells. In 2007 and 2006, we added over 10,000 acres
adjacent to our acreage and acquired over 80 square miles of 3-D seismic data
adding additional drilling inventory. For the year ended December 31,
2007, our average net daily production from the Lobo Trend was 40.8
MMcfe/d. Our working interests range from 50% - 100% but most of our
acreage is 100% owned and operated. We have two drilling rigs under
contract which should drill 48 wells in 2008. In 2007, we drilled 42 gross wells
of which 33 were successful. We have identified over 100 potential drilling
locations on our acreage and plan to participate in the drilling of 48 wells in
2008.
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 trend produces from tight sands
with low permeabilities and high pressures at depths from 7,500 to 10,000
feet.
Perdido
Perdido Sand Trend. We own a
50% non-operating working interest in approximately 9,000 net acres in the South
Texas, Perdido Sand Trend. The Perdido Sands are comprised of tight
natural gas sands and are in isolated fault blocks that are stratigraphically
trapped below the Upper Wilcox structures at approximately 8,000 to 9,500 feet.
The program of horizontal drilling with fracture stimulations has been very
successful in maximizing natural gas recovery. We plan to increase
our current acreage position of 9,000 net acres and seismic position of 100
square miles and to continue to coordinate with the operator to improve
horizontal drilling techniques to lower cost and increase
performance. For the year ended December 31, 2007, our average
net daily production was 9.5 MMcfe/d from 42 producing wells (19 horizontal and
23 vertical). We participated in the drilling of ten gross wells in 2007 of
which all were successful. We have identified over
50 potential drilling locations on our acreage and plan to participate in the
drilling of ten wells in 2008.
State
Waters of Texas
Sabine Lake. We
own a 50% operated working interest through a joint venture in Sabine Lake,
within Texas State Waters of Jefferson County and Louisiana State Waters of
Cameron Parish. During 2007, we drilled four gross wells of
which three were successful. Facilities and pipelines were
constructed and the wells began producing in November and December of 2007 with
a net production rate of 13 MMcfe/d at year-end 2007. We currently
hold interest in approximately 6,000 net acres with 70 square miles of 3-D
seismic data. We are evaluating additional drilling potential in the
region for 2008.
Other
Onshore
Live Oak County Prospect.
Through the interpretation of 3-D seismic data, we identified and participated
in the drilling of a 16,500 foot test in Live Oak County, Texas in the fourth
quarter of 2007 and tested the well in December 2007. The well is
currently being completed with first production expected in the second quarter
of 2008. We have identified further opportunities within an Area of
Mutual Interest (“AMI”) agreement covering approximately 22,000 gross
acres.
In the
Other Onshore region, we currently have approximately 26,000 net acres under
lease with an average of a 40% non-operated working interest. In
2007, we drilled 18 gross wells of which 16 were successful and are evaluating
additional drilling potential in the region for 2008.
Gulf
of Mexico
Federal Waters. We
own working interests in 12 offshore blocks ranging from 20% to 100% working
interest with approximately 36,000 net acres. For the year ended
December 31, 2007, our average net daily production from these blocks was 13
MMcfe/d. Under the PTRA with Calpine, we have its full support and
the Bankruptcy Court’s order to secure the outstanding MMS ministerial approval
for South Pelto 17 and South Timbalier 252. Due to the absence of
production, the MMS leases for East Cameron 76 and South Timbalier 235 have
expired.
During
2007, three wells previously drilled and completed in 2006 were placed on
production in the first half of 2007, of which we own a 25% - 50% working
interest. In 2007, as part of our participation in a joint venture, two wells
with a 50% non-operated working interest were drilled, resulting
in one dry hole and one well pending completion.
We have
entered into an 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.
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:
|
|
For
the Year Ended December 31, 2007 (1)
|
|
|
|
Natural
Gas
(Bcf)
|
|
|
Oil
(MBbls)
|
|
|
Equivalents
(Bcfe)
|
|
California
|
|
|
15.9 |
|
|
|
24.2 |
|
|
|
16.1 |
|
Rocky
Mountains
|
|
|
2.2 |
|
|
|
5.0 |
|
|
|
2.2 |
|
Mid-Continent
|
|
|
0.2 |
|
|
|
15.4 |
|
|
|
0.3 |
|
Lobo
|
|
|
14.2 |
|
|
|
113.3 |
|
|
|
14.9 |
|
Perdido
|
|
|
3.4 |
|
|
|
18.9 |
|
|
|
3.5 |
|
Texas
State Waters
|
|
|
0.8 |
|
|
|
31.7 |
|
|
|
1.0 |
|
Other
Onshore
|
|
|
2.3 |
|
|
|
131.9 |
|
|
|
2.9 |
|
Gulf
of Mexico
|
|
|
3.5 |
|
|
|
220.8 |
|
|
|
4.9 |
|
|
|
|
42.5 |
|
|
|
561.2 |
|
|
|
45.8 |
|
___________________________________
|
(1)
|
Excludes
certain interests in leases and wells 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 can not 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, 2007, we had 418.4 Bcfe of proved oil and natural gas
reserves, including 400.2 Bcf of natural gas and 3,021 MBbls of oil and
condensate. Using prices as of December 31, 2007, the estimated
standardized measure of discounted future net cash flows was $954.2
million. The following table sets forth by operating area a summary
of our estimated net proved reserve information as of December 31,
2007:
|
|
Estimated
Proved Reserves at December 31, 2007 (1)(2)(3)
|
|
|
|
Developed
(Bcfe)
|
|
|
Undeveloped
(Bcfe)
|
|
|
Total
(Bcfe)
|
|
|
Percent
of Total Reserves
|
|
California
|
|
|
107.5 |
|
|
|
39.4 |
|
|
|
146.9 |
|
|
|
35 |
% |
Rocky
Mountains
|
|
|
35.6 |
|
|
|
7.0 |
|
|
|
42.6 |
|
|
|
10 |
% |
Mid-Continent
|
|
|
1.5 |
|
|
|
0.5 |
|
|
|
2.0 |
|
|
|
0 |
% |
Lobo
|
|
|
97.9 |
|
|
|
57.2 |
|
|
|
155.1 |
|
|
|
37 |
% |
Perdido
|
|
|
10.6 |
|
|
|
8.4 |
|
|
|
19.0 |
|
|
|
5 |
% |
Texas
State Waters
|
|
|
10.3 |
|
|
|
- |
|
|
|
10.3 |
|
|
|
2 |
% |
Other
Onshore
|
|
|
20.4 |
|
|
|
2.6 |
|
|
|
23.0 |
|
|
|
6 |
% |
Gulf
of Mexico
|
|
|
17.8 |
|
|
|
1.7 |
|
|
|
19.5 |
|
|
|
5 |
% |
Total
|
|
|
301.6 |
|
|
|
116.8 |
|
|
|
418.4 |
|
|
|
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 an estimate of 20 Bcfe of proved oil and
natural gas reserves for interests in certain leases and wells being
a portion of the properties described in footnote 2
below.
|
|
(2)
|
At
the July 2005 closing of the Acquisition, we withheld some $75 million for
interests in leases and wells (including 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 consents the parties believed at that time were
required.
|
|
(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 under the Purchase Agreement we believe Calpine is contractually
obligated to assist in resolving.
|
2007
Capital Expenditures
The
following table summarizes information regarding development and exploration
capital expenditures for the years ended December 31, 2007 and 2006
(Successor), six months ended December 31, 2005 (Successor) and the six
months ended June 30, 2005 (Predecessor).
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year
Ended
|
|
|
Year
Ended
|
|
|
Six
Months Ended
|
|
|
Six
Months Ended
|
|
|
|
December
31, 2007
|
|
|
December
31, 2006
|
|
|
December
31, 2005
|
|
|
June
30, 2005
|
|
|
|
|
|
|
(In
thousands)
|
|
Capital
Expenditures by Operating Area:
|
|
|
|
|
|
|
|
|
|
|
|
|
California
|
|
$ |
58,493 |
|
|
$ |
39,691 |
|
|
$ |
3,933 |
|
|
$ |
4,572 |
|
Rocky
Mountains
|
|
|
23,904 |
|
|
|
15,299 |
|
|
|
3,035 |
|
|
|
1,102 |
|
Mid-Continent
|
|
|
4,974 |
|
|
|
3,371 |
|
|
|
317 |
|
|
|
220 |
|
Lobo
|
|
|
82,665 |
|
|
|
51,911 |
|
|
|
6,775 |
|
|
|
2,020 |
|
Perdido
|
|
|
22,636 |
|
|
|
25,971 |
|
|
|
9,268 |
|
|
|
12,441 |
|
Texas
State Waters
|
|
|
27,000 |
|
|
|
13,028 |
|
|
|
3,023 |
|
|
|
3,417 |
|
Other
Onshore
|
|
|
24,822 |
|
|
|
10,207 |
|
|
|
10,831 |
|
|
|
2,300 |
|
Gulf
of Mexico
|
|
|
28,523 |
|
|
|
17,958 |
|
|
|
9,369 |
|
|
|
4,556 |
|
Leasehold
|
|
|
8,838 |
|
|
|
16,383 |
|
|
|
9,224 |
|
|
|
2,617 |
|
New
acquisitions
|
|
|
38,656 |
|
|
|
35,105 |
|
|
|
5,524 |
|
|
|
- |
|
Delay
rentals
|
|
|
1,409 |
|
|
|
728 |
|
|
|
143 |
|
|
|
443 |
|
Geological
and geophysical/seismic
|
|
|
4,422 |
|
|
|
3,748 |
|
|
|
5,659 |
|
|
|
513 |
|
Total
capital expenditures (1)
|
|
$ |
326,342 |
|
|
$ |
233,400 |
|
|
$ |
67,101 |
|
|
$ |
34,201 |
|
___________________________________
|
(1)
|
Capital
expenditures for the year ended December 31, 2007 (Successor) excludes
capitalized internal costs directly identified with acquisition,
exploration and development activities of $5.5 million, capitalized
interest of $2.4 million and corporate other capital costs of $1.8
million. Capital expenditures for the year ended December 31, 2006
(Successor) excludes capitalized internal costs of $3.4 million,
capitalized interest of $2.1 million and corporate other capital costs of
$1.7 million. The six months ended December 31, 2005 (Successor)
excludes capitalized interest of $0.6 million, corporate other capital
costs of $1.6 million and capitalized internal costs of $1.7
million. Corporate other capital 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.
|
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, 2007. “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
|
|
|
39,888 |
|
|
|
32,213 |
|
|
|
52,547 |
|
|
|
44,208 |
|
|
|
179 |
|
|
|
152 |
|
Rocky
Mountains
|
|
|
178,393 |
|
|
|
158,203 |
|
|
|
18,549 |
|
|
|
13,525 |
|
|
|
161 |
|
|
|
156 |
|
Mid-Continent
|
|
|
120 |
|
|
|
47 |
|
|
|
9,938 |
|
|
|
2,575 |
|
|
|
28 |
|
|
|
5 |
|
Lobo
|
|
|
28,755 |
|
|
|
31,203 |
|
|
|
61,949 |
|
|
|
46,659 |
|
|
|
248 |
|
|
|
215 |
|
Perdido
|
|
|
14,916 |
|
|
|
7,385 |
|
|
|
4,594 |
|
|
|
2,094 |
|
|
|
41 |
|
|
|
20 |
|
Texas
State Waters
|
|
|
5,706 |
|
|
|
2,801 |
|
|
|
10,038 |
|
|
|
3,193 |
|
|
|
7 |
|
|
|
3 |
|
Other
Onshore
|
|
|
19,689 |
|
|
|
8,709 |
|
|
|
44,508 |
|
|
|
16,905 |
|
|
|
285 |
|
|
|
46 |
|
Gulf
of Mexico (2)
|
|
|
17,495 |
|
|
|
9,497 |
|
|
|
46,994 |
|
|
|
26,886 |
|
|
|
12 |
|
|
|
9 |
|
|
|
|
304,962 |
|
|
|
250,058 |
|
|
|
249,117 |
|
|
|
156,045 |
|
|
|
961 |
|
|
|
606 |
|
___________________________________
|
(1)
|
This
table includes acreage relating to properties for which we believe Calpine
is contractually obligated to assist us in resolving, either on the basis
of further assurances under the Purchase Agreement and PTRA, or on other
legal basis.
|
|
(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, 2007 which is subject to expiration in 2008, 2009, 2010, and
thereafter.
2008
|
|
|
2009
|
|
|
2010
|
|
|
Thereafter
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
36,115 |
|
|
|
27,229 |
|
|
|
42,806 |
|
|
|
35,287 |
|
|
|
53,309 |
|
|
|
45,956 |
|
|
|
172,732 |
|
|
|
141,586 |
|
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.
|
|
Gross
Wells
|
|
|
|
Exploratory
|
|
|
Development
|
|
|
|
Productive
|
|
|
Dry
|
|
|
Total
|
|
|
Productive
|
|
|
Dry
|
|
|
Total
|
|
2007
|
|
|
11.0 |
|
|
|
7.0 |
|
|
|
18.0 |
|
|
|
149.0 |
|
|
|
28.0 |
|
|
|
177.0 |
|
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 |
|
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
|
|
2007
|
|
|
7.5 |
|
|
|
5.1 |
|
|
|
12.6 |
|
|
|
130.2 |
|
|
|
26.5 |
|
|
|
156.7 |
|
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 |
|
Marketing
and Customers
Pursuant
to our natural gas purchase and sales contract with CES whose
term runs through December 2009, we are obligated to sell all of the
then-existing and future production from our California leases in production as
of May 1, 2005 based on market prices. Calpine maintains a
right of first refusal in relation to this dedicated California production for a
term of 10 years after December 31, 2009. For the month of
December 2007, this dedicated California production comprised approximately
30% 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, provided Calpine has fully cured such payment default, we
are obligated under the contract to resume natural gas sales to Calpine. We
believe that Calpine’s bankruptcy and their emergence from Bankruptcy has not
had a 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 purchase and sales contract, to
parties other than Calpine, an affiliate of Calpine is under contract through
June 30, 2009 to provide us administrative services in connection with such
marketing efforts in accordance with the contract terms.
All of
our other production is sold to various purchasers, including Calpine, on a
competitive basis.
Major
Customers
For the
year ended December 31, 2007, we had one major customer, Calpine Energy Services
(“CES”), which accounted on an aggregated basis for approximately 55% of our
consolidated annual revenue.
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. 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.
Government
Regulation
The oil
and gas industry is subject to extensive laws that are subject to amendment or
expansion. These laws have a significant impact on oil and gas
exploration, production and marketing activities, and increase the cost of doing
business, and consequently, affect profitability. Some of the legislation and
regulation affecting the oil and gas industry carry significant penalties for
failure to comply. While there can be no assurance that the Company will not
incur fines or penalties, we believe we are currently in compliance
with the applicable federal, state and local laws. Because enactment
of new laws affecting the oil and gas business is common and because existing
laws are often amended or reinterpreted, we are unable to predict the future
cost or impact of complying with such laws. We do not expect that any
of these laws would affect us in a materially different manner than any other
similarly sized oil and gas company operating in the United
States. The following are significant areas of the laws.
Exploration
and Production Regulation
Oil and
natural gas production is regulated under a wide range of federal, state and
local statutes, rules, orders and regulations, including laws related to
location of wells, drilling and casing of wells, well production limitations;
spill prevention plans; surface use and restoration; platform, facility and
equipment removal; the calculation and disbursement of royalties; the plugging
and abandonment of wells; bonding; permits for drilling operations; and
production, severance and ad valorem taxes. Oil and gas companies can encounter
delays in drilling from the permitting process and requirements. Our
operations are subject to regulations governing operation restrictions and
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 prevention of flaring or venting of natural
gas. The conservation laws have the effect of limiting 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.
Environmental
and Occupation Regulations
We are
subject to extensive federal, state and local statutes, rules and regulations
concerning protection of the environment and protection of wildlife;
restrictions on the emission or discharge of materials into the environment; and
occupational safety and health. We have made and will continue to make
expenditures in our efforts to comply with these requirements. In
this regard, we believe that we currently hold all up-to-date permits,
registrations and other authorizations to the extent they are required by our
operations under the current regulatory scheme. We maintain insurance
at industry customary levels to limit our financial exposure in the event of a
substantial environmental claim resulting from sudden, unanticipated and
accidental discharges of certain prohibited substances into the
environment. Such insurance might not cover the complete amount of
such a claim and would not cover fines or penalties for a violation of an
environmental law.
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.
Filings
of Reserve Estimates with Other Agencies
We
annually file estimates of our oil and gas reserves with the United States
Department of Energy (“DOE”) for those properties which we
operate. During 2007, we filed estimates of our oil and gas reserves
as of December 31, 2006 with the DOE, which differ by five percent or less from
the reserve data presented in the Annual Report on Form 10-K for the year ended
December 31, 2006. For information concerning proved
natural gas and crude oil reserves, refer to Item 8. Consolidated Financial
Statements and Supplementary Data, Supplemental Oil and
Gas Disclosures.
Employees
As of
February 18, 2008, we have approximately 152 full time employees. We also
contract for the services of independent consultants involved in land,
regulatory, accounting, financial, legal 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 website that contains reports, proxy and
information statements and other information that is filed electronically with
the SEC. The website 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 and certain matters that have survived Calpine’s bankruptcy may
adversely affect us in several respects.
Calpine,
its creditors or interest holders have challenged the fairness of some or all of
the Acquisition.
On June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court (the “Lawsuit”). The complaint alleges that the purchase by us
of the domestic oil and natural gas business formally owned by Calpine (the
“Assets”) in July 2005 for $1.05 billion, prior to Calpine's declaring
bankruptcy, was completed when Calpine was insolvent and was for less than a
reasonably equivalent value. Through the Lawsuit, Calpine is seeking
(i) monetary damages for the alleged shortfall in value it received for the
Assets, which it estimates to be at least approximately $400 million plus
interest, or (ii) in the alternative, return of the Assets. We deny
and intend to vigorously defend against all claims made by Calpine. The Official
Committee of Equity Security Holders and the Official Committee of the Unsecured
Creditors both intervened in the Lawsuit for the stated purpose of monitoring
the proceedings because these committees claim to have an interest in the
Lawsuit, which we dispute because creditors may be paid in full under Calpine’s
Plan of Reorganization without regard to the Lawsuit and equity holders cannot
benefit from fraudulent conveyance actions. On September 10, 2007, we
filed a motion to dismiss the complaint, which the Bankruptcy Court heard on
October 24, 2007. Following the hearing, the Bankruptcy Court denied
our motion on the basis that certain issues we raised in our motion were
premature as the bankruptcy process had not yet established how much Calpine’s
creditors would receive. We filed our answer and counterclaims
against Calpine on November 5, 2007. Under Calpine’s Plan of
Reorganization approved by the Bankruptcy Court on December 19, 2007, the
Official Committee of Equity Security Holders was dissolved as of the January
31, 2008 effective date and no longer has any interest in the
Lawsuit. While the Unsecured Creditors Committee also officially
dissolved as of the same effective date, there are provisions that will allow it
to remain involved in lawsuits to which it is a party, which may include this
Lawsuit.
The
Bankruptcy Court has not set a trial date for the Lawsuit, but the parties are
in current agreement that discovery may continue up through April
2008. If after a trial on the merits, the Bankruptcy Court determines
that Calpine has met its burden of proof, the Bankruptcy Court could void the
transfer or take other actions against us, including (i) setting aside the
Acquisition and returning some or all of our purchase price and/or giving us a
first lien on all the properties and assets we purchased in the Acquisition or
(ii) entering a judgment requiring us to pay Calpine the amount, if any, by
which the fair value of the business transferred, as determined by the
Bankruptcy Court as of the date of the transaction, exceeded the purchase price
determined and paid in July 2005. If the Bankruptcy Court should set aside the
Acquisition, it would have a material adverse effect upon our business, results
of operations, financial condition or cash flows in that substantially all of
the properties received by us 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 have a material adverse
effect upon our results of operation and financial condition 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.
On June
20, 2007, Calpine filed with the Bankruptcy Court its proposed Plan of
Reorganization and disclosure statement. In the disclosure statement,
Calpine revealed that it had not yet made a decision on whether to assume or
reject its remaining obligations and duties under the Purchase Agreement,
including the interrelated agreements, which set forth the terms and agreements
related to Calpine’s sale of its oil and gas assets to us. In its
proposed supplement to the plan filed on the same date, however, Calpine
indicated its desire to assume the NAESB agreements under which Rosetta sells
gas to Calpine Energy Services (“CES”) and the Calpine
Producer Services, L.P. (“CPS”) marketing agreement under which CPS
provides certain marketing services on our behalf. We contend that
all of the transaction documents constitute one agreement in regard to the
Acquisition and must, therefore, be assumed or rejected in their entirety as one
agreement and will vigorously oppose any effort by Calpine to treat any aspect
of the transaction documents as a stand-alone agreement. Following
negotiations with Calpine with respect to its Plan of Reorganization and its
efforts to assume portions of the Purchase Agreement, we agreed to extend the
deadline for Calpine to assume or reject the Purchase Agreement with Rosetta
related to the transaction until fifteen days following the conclusion of the
Lawsuit. In return, Calpine has agreed not to assume or reject the
CPS Marketing Agreement or the NAESB agreements until the conclusion of the
litigation with Rosetta; however, if Rosetta prevails in the litigation, Calpine
has agreed it will assume the Purchase Agreement and all other agreements from
the transaction.
Although
Calpine had not made its election to assume or reject the Purchase Agreement, on
August 3, 2007, we executed a Partial Transfer and Release Agreement (“PTRA”)
with Calpine, which was approved by the Bankruptcy Court on September 11, 2007,
without prejudice to the other pending claims, disputes, and defenses between
Calpine and us. As part of the PTRA, we agreed to enter into a new
CPS marketing agreement for a period of two years, effective as of July 1, 2007,
and concluding on June 30, 2009; however, the marketing agreement is subject to
earlier termination by us upon the occurrence of certain events. In
return, Calpine has provided documents to resolve legal title issues as to
certain previously purchased oil and gas properties located in the Gulf of
Mexico, California and Wyoming (“Properties”). Under the PTRA, we
have also agreed to assume all liabilities with respect to those Properties,
such as plugging and abandonment, as well as all liabilities and rights
associated with any under- or over-payment to the State of California as it
relates to certain state land.
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 was to be delivered by Calpine to quiet title related to our
ownership of these properties following closing. Those properties
that may still be subject to ministerial governmental action approving us as
qualified assignee and operator were included as part of the Properties being
addressed under the PTRA. For certain other properties, the
documentation delivered by Calpine at closing was incomplete. Calpine has
not made a decision on whether to perform its remaining obligations under the
Purchase Agreement with us and thus perform these required further assurances as
to title. On October 30, 2007, the California State Lands Commission approved
Calpine’s assignment of its interests in a certain State of California lease and
certain rights-of-way, completing the transfer of those properties to us and
resolving open issues on an audit the State had performed on the
properties. We are awaiting the final, ministerial approvals from the
Mineral Management Service (“MMS”) for the assignment of Calpine’s interests in
those PTRA Properties for which the federal government is the lessor. The
PTRA does not otherwise address the Non-Consent Properties which Calpine
withheld from the July 2005 closing due to lack of receipt of the lessors’
consents determined at that time (in many instances mistakenly) as needed for
transfer and for which we withheld from the closing of the transaction with
Calpine approximately $75 million of the purchase price. Until the
Purchase Agreement is assumed by Calpine, we will not have record title to the
interests in the leases and wells specified in the Purchase Agreement as
Non-Consent Properties for which Calpine retained an ownership
interest.
The
bankruptcy proceeding may continue to prevent, frustrate or delay our
ability to receive corrective documentation from Calpine for certain properties
that we paid for and bought from Calpine, 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 approvals that state we are qualified
assignees and operators, 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, all of the same being covered, we believe, by the further
assurances provision of the Purchase Agreement, that uncertainty remains pending
conclusion of the Lawsuit as to the exact details for each property involved and
how, when and if this will be able to be secured or accomplished. As
noted above, a number of these open issues were addressed under the PTRA between
us and Calpine, and we have obtained or are in the process of obtaining proper
legal title as to the PTRA Properties.
Additionally,
on June 29, 2006, Calpine filed a Section 365 motion in connection with its
pending bankruptcy proceeding seeking entry of an order (which was granted as to
the substantial portion of these leases) 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 business, results of operations, financial position or
cash flows 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 by the Calpine bankruptcy from our business and
operational matters, our business, results of operations, financial position or
cash flows could be materially 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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Conservation
of resources;
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Regional
price differentials and quality differentials of oil and natural
gas;
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Domestic
and foreign governmental regulations, actions and
taxes;
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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 position, 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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Compliance
with governmental regulations;
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Mechanical
difficulties; and
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Unavailability
or high cost of equipment, drilling rigs, supplies or
services.
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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
financial position, results of operations and cash flows. Calpine’s recent
emergence from bankruptcy reduces the likelihood of failure, but because we have
taken the legal position that any rejection by Calpine of the Purchase
Agreement, is also a rejection of the parties’ natural gas and sales agreements,
this could result in the failure of Calpine to continue purchasing natural gas
from us.
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 CES whose
term runs through December 2009, we are obligated to sell all of the
then-existing and future production from our California leases in production as
of May 1, 2005 based on market prices. Calpine maintains a right of
first refusal for a term of 10 years after December 31,
2009. For the month of December 2007, this dedicated
California production comprised approximately 30% of our current overall
production based on an equivalent basis. Additionally, under separate monthly
spot agreements, we may sell some of our natural gas production 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, 2007 would be approximately $3.1 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 will depend on our ability to obtain financing beyond
our cash flow from operations. We may 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.
Additionally, we have secured a written waiver from our lenders in connection
with the Lawsuit based on existing events and our belief concerning those
events, and have an ongoing obligation to notify our lenders of all significant
developments in the Lawsuit. A more detailed description of our
credit facilities is included in Item 7 “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 and obligations associated with the Lawsuit
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
cancelled 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 financial position, results of operations and cash
flows.
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. As noted above, the estimated reserve quantities and
present value calculations exclude the estimates attributable to interests in
certain leases and wells being a portion of the Non-Consent Properties specified
in the Purchase Agreement. The
estimated reserve quantities and present value calculations include
properties subject to additional documentation, or completion
of documentation, including ministerial actions by federal or state
agencies for which we believe Calpine is contractually obligated to assist in
resolving, along
with certain other leases, concerning which Calpine has asserted an ownership
interest under its Section 365 motion and order in the Bankruptcy
Court. The estimated reserve quantities and present value
calculations may be impacted depending on the outcome of the Lawsuit and whether
Calpine assumes or rejects the Purchase Agreement. 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 engineers control. 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. As an
example, Netherland Sewell’s reserve report for year end 2007 includes the
downward revision for certain proved undeveloped reserves located in South Texas
due to the actual production performance history for wells we have drilled in
this area since the Acquisition. 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 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. Expense recorded in one period may not be
reversed in a subsequent period even though higher natural gas and crude oil
prices may have increased the ceiling applicable in the subsequent
period.
For the
year ended December 31, 2007, there was no write-down recorded. Due to the
volatility of commodity prices, should natural gas prices decline in the future,
it is possible that a write-down could occur. See Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations, Critical Accounting Policies and Estimates for further
information.
Government
laws and regulations can change.
Our
activities are subject to federal, state and local laws and regulations.
Extensive laws, regulations and rules relate to activities and operations in the
oil and gas industry. Some of the laws, regulations and rules
contain provisions for significant fines and penalties for
non-compliance. Changes in laws and regulations could affect our
costs of operations and our profitability. Changes in laws and
regulations could also affect production levels, royalty obligations, price
levels, environmental requirements, and other matters affecting our
business. We are unable to predict changes to existing laws and
regulations or additions to laws and regulations. Such changes could
significantly impact our business, results of operations, cash flows, financial
position and future growth.
Our
business requires a sufficient level of staff with technical expertise,
specialized knowledge and training and a high degree of management
experience.
Our
success is largely dependent our ability to attract and retain personnel with
the skills and experience required for our business. An inability to
sufficiently staff our operations or 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 position, results of
operations, cash flows 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 position, results of operations and 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 position, results of
operations and 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. Under
interruptible or short term transportation agreements, the transportation of our
gas may be interrupted due to capacity constraints on the applicable system, for
maintenance or repair of the system or for other reasons specified by the
particular agreements. 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.
The
unavailability or high cost of drilling rigs, equipment, supplies, personnel and
oil field services could adversely affect our ability to execute our exploration
and development plans on a timely basis and within our budget.
Our
industry is cyclical and, from time to time, there is a shortage of drilling
rigs, equipment, supplies or qualified personnel. During these periods, the
costs and delivery times of rigs, equipment and supplies are substantially
greater. In addition, the demand for, and wage rates of, qualified drilling rig
crews rise as the number of active rigs in service increases. As a result of
increasing levels of exploration and production in response to strong prices of
oil and natural gas, the demand for oilfield services has risen, and the costs
of these services are increasing, while the quality of these services may
suffer. If the unavailability or high cost of drilling rigs, equipment, supplies
or qualified personnel were particularly severe in Texas and California, we
could be materially and adversely affected because our operations and properties
are concentrated in those areas.
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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Uncontrollable
flows of oil, natural gas or well
fluids;
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Hurricanes,
tropical storms, earthquakes, mud slides, and
flooding;
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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, financial
position, results of operations 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
matters and costs can be significant.
The oil
and natural gas business is subject to various federal, state, and local laws
and regulations relating to discharge of materials into, and protection of, the
environment. Such laws and regulations may impose liability on us for
pollution clean-up, remediation, restoration and other liabilities arising from
or related to our operations. 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. We also may be liable for environmental damages caused by
the previous owners or operators of properties we have purchased or are
currently operating. The cost of future compliance is uncertain and is subject
to various factors, including future changes to laws and
regulations. We have no assurance that future changes in or additions
to the environmental laws and regulations will not have a significant impact on
our business, results of operations, cash flows, financial condition and future
growth.
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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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 unique
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.
We have
also entered into a series of interest rate swap agreements to hedge the change
in the variable interest rates associated with our debt under our credit
facility. If interest rates should fall below the rate established in
the hedge, we could be exposed to losses associated with these
hedges.
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.
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 Agreement to obtain payment from
them. We are exposed to the risk that, in these circumstances and in light of
the Lawsuit, 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 and
the PTRA, 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. In connection with the PTRA, we have submitted
the required documents and are waiting for ministerial approvals from the
MMS. 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 flows 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 not advised us of any change in the inactive status of the SEC’s informal
inquiry in this regard. Our understanding is that Calpine 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, 2007, 50,998,073 shares of common stock were issued, including
899,150 shares of restricted stock issued to certain employees and
directors. The majority of these shares vest over a three year
period. Of the restricted stock that has been granted, 443,725 shares
had vested as of December 31, 2007 and the remaining shares will vest no later
than 2012. 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. In
addition, we have issued 1,062,600 options to purchase common stock issued to
certain employees and directors, of which 90,000 have been exercised as of
December 31, 2007. The potential issuance of 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.
None
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, Rio Vista, California and Magnolia, Arkansas. 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 below in the “Open Issues Regarding Legal Title to Certain Properties”
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
Lawsuit and its possible rejection of the Purchase Agreement may delay or
frustrate our ability to complete additional transfers of properties for which
legal title was not obtained or secure curative documentation to correct
possible clouds on title as of July 7, 2005. See item 3. Legal
Proceedings for further information concerning the Lawsuit and Calpine’s
possible rejection of the Purchase Agreement, and the effect of possible losses
in connection with open issues regarding legal title to certain
properties.
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 consolidated financial statements.
Calpine
Bankruptcy
On
December 20, 2005, Calpine and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”). On December 19, 2007, the Bankruptcy Court approved
Calpine’s Plan of Reorganization. On January 31, 2008, Calpine and
certain of its subsidiaries emerged from Bankruptcy.
Calpine’s
Lawsuit Against Rosetta
On June
29, 2007, Calpine filed an adversary proceeding against us in the Bankruptcy
Court (the “Lawsuit”). The complaint alleges that the purchase by Rosetta of the
domestic oil and natural gas business owned by Calpine (the “Assets”) in July
2005 for $1.05 billion, prior to Calpine filing for bankruptcy, was completed
when Calpine was insolvent and was for less than a reasonably equivalent value.
Through the Lawsuit, Calpine is seeking (i) monetary damages for the alleged
shortfall in value it received for these Assets which it estimates to be at
least approximately $400 million plus interest, or (ii) in the alternative,
return of the Assets from us. We believe that the allegations in the Lawsuit are
without merit, and we continue to believe that it is unlikely that this
challenge by Calpine to the fairness of the Acquisition will be successful upon
the ultimate disposition of this litigation in the Bankruptcy Court, or if
necessary, in the appellate courts. The Official Committee of Equity Security
Holders and the Official Committee of the Unsecured Creditors both intervened in
the Lawsuit for the stated purpose of monitoring the proceedings because the
committees claimed to have an interest in the Lawsuit, which we dispute because
we believe creditors may be paid in full under Calpine’s Plan of Reorganization
without regard to the Lawsuit and equity holders have no interest in fraudulent
conveyance actions. Under Calpine’s Plan of Reorganization approved
by the Bankruptcy Court on December 19, 2007, the Official Committee of Equity
Security Holders was dissolved as of the January 31, 2008 effective date and no
longer has any interest in the Lawsuit. While the Unsecured Creditors
Committee also was officially dissolved as of the same effective date, there are
provisions under the approved Plan of Reorganization that will allow it to
remain involved in lawsuits to which it is a party, which may include this
Lawsuit.
On
September 10, 2007, we filed a motion to dismiss the Lawsuit or in the
alternative, to stay the Lawsuit. The Bankruptcy Court conducted a hearing upon
our motion on October 24, 2007. Following the hearing, the
Bankruptcy Court denied our motion on the basis that certain issues we raised in
our motion were premature as the bankruptcy process had not yet established how
much Calpine’s creditors would receive. On November 5, 2007, we filed
our answer, affirmative defenses and counterclaims with respect to the Lawsuit,
denying the allegations set forth in both counts of the Lawsuit, and asserting
affirmative defenses to Calpine’s claims as well as affirmative counterclaims
against Calpine related to the Acquisition for (i) breach of covenant of
solvency, (ii) fraud and fraud in a real estate transaction, (iii) breach of
contract, (iv) conversion, (v) civil theft and (vi) setoff. The
parties are currently in agreement that discovery may continue in the Lawsuit
until April 2008. The Bankruptcy Court has not set a trial date for
the lawsuit.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that the Purchase and
Sale Agreement and interrelated agreements concurrently executed therewith,
dated July 7, 2005, by and among Calpine, us, and various other signatories
thereto (collectively, the “Purchase Agreement”) are “executory contracts”,
which Calpine may assume or reject. Following the July 7, 2005
closing of the Acquisition and as of the date of Calpine’s bankruptcy filing,
there were open issues regarding legal title to certain properties included in
the Purchase Agreement. On September 25, 2007, the Bankruptcy Court approved
Calpine’s Disclosure Statement accompanying its proposed Plan of Reorganization
under Chapter 11 of the Bankruptcy Code, in which Calpine revealed it had
not yet made a decision as to whether to assume or reject its remaining duties
and obligations under the Purchase Agreement. We may contend that the
Purchase Agreement is not an executory contract which Calpine may choose to
reject. If the Court were to determine that the Purchase Agreement is
an executory contract, we may contend the various agreements entered into as
part of the transaction constitute a single contract for purposes of assumption
or rejection under the Bankruptcy Code, and we may argue that Calpine cannot
choose to assume certain of the agreements and to reject others. This
issue may be contested by Calpine. If the Purchase Agreement is held
to be executory, the deadline by when Calpine must exercise its decision to
assume or reject the Purchase Agreement and the further duties and obligations
required therein would normally have been the date on which Calpine’s
Plan of Reorganization was confirmed; however, in order to address certain
issues, we and Calpine have agreed to extend this deadline until fifteen days
following the entry of a final, unappealable order in the Lawsuit, and the
parties set forth this agreement in the proposed Plan of Reorganization approved
by the Bankruptcy Court on December 19, 2007.
Open
Issues Regarding Legal Title to Certain Properties
Under the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to interests in certain properties. At the closing of the
Acquisition on July 7, 2005, we retained approximately $75 million of the
purchase price in respect to leases and wells identified by Calpine as requiring
third-party consents or waivers of preferential rights to purchase that were not
received by the parties before closing (“Non-Consent
Properties”). The interests in the Non-Consent Properties were not
included in the conveyances delivered at the closing. Subsequent
analysis determined that a significant portion of the Non-Consent Properties did
not require consents or waivers. For that portion of the Non-Consent
Properties for which third-party consents were in fact required and for which
either us or Calpine obtained the required consents or waivers, as well as for
all Non-Consent Properties that did not require consents or waivers, we contend
Calpine was and is obligated to have transferred to us the record title, free of
any mortgages and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. We have retained $7.1 million of the purchase price
under the Purchase Agreement for the Non-Consent Properties subject to the
third-party preferential right, and, in addition, a post-closing adjustment is
required to credit us for approximately $0.3 million for a property which was
transferred to us but, if necessary, will be transferred to the appropriate
third party under its exercised preferential purchase right upon Calpine’s
performance of its obligations under the Purchase Agreement.
We
believe all conditions precedent for our receipt of record title, free of any
mortgages or other liens, for substantially all of the Non-Consent Properties
(excluding that portion of these properties subject to the third-party
preferential right) were satisfied earlier, and certainly no later, than
December 15, 2005, when we tendered the amounts necessary to conclude the
settlement of the Non-Consent Properties.
We
believe we are the equitable owner of each of the Non-Consent Properties for
which Calpine was and is obligated to have transferred the record title and that
such properties are not part of Calpine’s bankruptcy estate. Upon our
receipt from Calpine of record title, free of any mortgages or other liens, to
these Non-Consent Properties (excluding that portion of these properties subject
to a validly exercised third party’s preferential right to purchase) and further
assurances required to eliminate any open issues on title to the remaining
properties discussed below, we have been prepared to conclude the remaining
aspects of the Acquisition. We have not included in our
statement of operations for the years ended December 31, 2007 and 2006 and six
months ended December 31, 2005, estimated net revenues and
related estimated production from interests in certain leases and
wells being a portion of the Non-Consent Properties, including those
properties subject to preferential rights.
On
September 11, 2007, the Bankruptcy Court entered an order approving that certain
Partial Transfer and Release Agreement (“PTRA”) negotiated by and between us and
Calpine which, among other things, resolves issues in regard to title of certain
of the other oil and natural gas properties we purchased from Calpine in the
Acquisition and for which payment was made to Calpine on July 7, 2005, and we
entered into a new Marketing and Services Agreement (“MSA”) with Calpine
Producer Services, L.P. (“CPS”) for a two-year period commencing on July 1, 2007
but which is subject to earlier termination by us on the occurrence of certain
events. The additional documentation received from Calpine under the PTRA
eliminates any open issues in our title and resolves any issues as to the
clarity of our ownership in certain properties located in the Gulf of Mexico,
California, and Wyoming (the “PTRA Properties”), including all oil and gas
properties requiring ministerial approvals, such as leases with the U.S.
Minerals Management Service (“MMS”), California State Lands Commission (“CSLC”)
and U.S. Bureau of Land Management (“BLM”). However, the PTRA was executed
without prejudice to Calpine’s fraudulent conveyance action or its right, if
any, to reject the Purchase Agreement, and without prejudice to our rights and
legal arguments in relation thereto, including our various
counterclaims. The PTRA did not otherwise address or resolve issues
with respect to the Non-Consent Properties and certain other
properties.
We
recorded the conveyances of those PTRA Properties in California not requiring
governmental agency approval. On October 30, 2007, the CSLC approved
the assignment of the State of California leases and rights of way to us from
Calpine and resolved open issues under an audit the State of California had
conducted as to these properties. While the documentation has
been filed with the MMS, we are still awaiting its ministerial approval for the
assignment of Calpine’s interests in MMS Federal Offshore leases for South Pelto
17 and South Timalier 252 to us.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to
whether Calpine will respond cooperatively as to the remaining outstanding
issues under the Purchase Agreement. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these remaining
issues whether under the Purchase Agreement or the PTRA, we will pursue all
available remedies, including but not limited to a declaratory judgment to
enforce our rights and actions to quiet title. After pursuing these matters, if
we experience a loss of ownership with respect to these properties without
receiving adequate consideration for any resulting loss to us, an outcome our
management considers to be unlikely upon ultimate disposition, including
appeals, if any, then we could experience losses which could have a material
adverse effect on our business, financial condition, statement of operations or
cash flows.
Sale
of Natural Gas to Calpine
In
addition to the issues involving legal title to certain properties, we executed,
as part of the interrelated agreements that constitute the Purchase Agreement,
certain natural gas sales agreements with Calpine Energy Services, L.P. (“CES”),
which also filed for bankruptcy on December 20, 2005. During the
period following Calpine’s filing for bankruptcy, CES has continued to make the
required deposits into our margin account and to timely pay for natural gas
production it purchases from our subsidiaries under these various natural gas
sales agreements. Although Calpine has indicated in a supplement to
its recently proposed Plan of Reorganization that it intends to assume the CES
natural gas sales agreements with us, we disagree that Calpine may assume
anything less than the entire Purchase Agreement and intend to oppose any effort
by Calpine to do less.
Calpine’s
Marketing of the Company’s Production
As part
of the PTRA, we entered into the MSA with CPS, effective July 1, 2007, which was
approved by the Bankruptcy Court on September 11, 2007. Under the MSA, CPS
provides marketing and related services in relation to the sales of our natural
gas production and charges us a fee. This MSA extends CPS’ obligations to
provide such services until June 30, 2009. The MSA is subject to early
termination by us upon the occurrence of certain events.
Events
within Calpine’s Bankruptcy Case
On June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to us in the Acquisition, to the extent those leases
constitute “unexpired leases of non-residential real property” and were not
fully transferred to us at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in certain oil and natural gas leases which Calpine contends it may
possess some legal interest. According to this motion, Calpine filed
its pending bankruptcy proceeding in order to avoid the automatic forfeiture of
any interest it may have in these leases by operation of a bankruptcy code
deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to us or Calpine, but we understand
Calpine’s motion was meant to allow Calpine to preserve and avoid forfeiture
under the Bankruptcy Code of whatever interest Calpine may possess, if any, in
these oil and natural gas leases. We dispute Calpine’s contention
that it may have an interest in any significant portion of these oil and natural
gas leases and intend to take the necessary steps to protect all of the our
rights and interest in and to the leases. Certain of these properties
have been subsequently addressed under the PTRA discussed above.
On July
7, 2006, we filed an objection in response to Calpine’s motion, wherein we
asserted that oil and natural gas leases constitute interests in real property
that are not subject to “assumption” under the Bankruptcy Code. In the
objection, we also requested that (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 MMS has subsequently
recognized us as owner and operator of all but two of these properties, two
other leases of offshore properties having expired, 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 could seek mediation to complete the
following:
|
·
|
Calpine’s
conveyance of its retained interest in the Non-Consent Properties to
us;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which we have already
paid Calpine; and
|
|
·
|
Resolution
of the final amounts we are to pay
Calpine.
|
At a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the CSLC that the Debtors’ Motion to Assume Non-Residential Leases and
Set Cure Amounts (the “Motion”), did not allow adequate time for an
appropriate response, Calpine withdrew from the list of oil and gas leases
that were the subject of the Motion those leases issued by the United
States (and managed by the MMS) (the “MMS Oil and Gas Leases”) and the
State of California (and managed by the CSLC) (the “CSLC Leases”).
Calpine, the Department of Justice and the State of California agreed to
an extension of the existing deadline to November 15, 2006 to assume or
reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the
Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases
are leases subject to Section 365. The effect of these actions was to
render our objection inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and us to arrive at a business
solution to all remaining issues including approximately $68 million
payable to Calpine for conveyance of the Non-Consent Properties (excluding
the properties subject to third party’s preferential
right).
|
On August
1, 2006, we filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts, as well as unliquidated damages in amounts that
have not presently been determined. In the event that Calpine elects
to reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, we anticipate we will be allowed to amend our proofs of
claim to assert any additional damages we suffer as a result of the ultimate
impact of Calpine’s refusal or failure to perform under the Purchase
Agreement. In the bankruptcy, Calpine may elect to contest or dispute
the amount of damages we seek in our proofs of claim. We will assert
all right to offset any of our damages against any funds we possess that may be
owed to Calpine. Until the allowed amount of our claims are finally
established and the Bankruptcy Court issues its rulings with respect to
Calpine’s approved Plan of Reorganization, we can not predict what amounts we
may recover from the Calpine bankruptcy should Calpine reject or refuse to
perform under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties further extended this deadline by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007
and more recently, October 31, 2007 with respect to the CSLC Leases. The
Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC
Leases which included appropriate language that we negotiated with Calpine for
our protection in this regard. The MMS Oil and Gas Leases and CSLC
Leases were included in the PTRA that was approved by the Bankruptcy Court on
September 11, 2007, with the result that there is no further need for the
parties to contest whether the MMS Oil and Gas Leases and the CLSC Leases are
appropriate for inclusion in Calpine’s 365 motion. The PTRA approved by the
Bankruptcy Court, among other things, resolves open issues in regard to our
title to ownership of all of the unexpired MMS Oil and Gas Leases and the CLSC
Leases. However, the PTRA was executed without prejudice to Calpine’s
fraudulent conveyance action or its rights, if any, to reject the Purchase
Agreement and our rights and legal arguments in relation thereto.
On June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine had indicated in its
filings with the Court that it believed substantial payments in the form of cash
or newly issued stock, or some combination thereof, would be made to unsecured
creditors under its proposed Plan of Reorganization that could conceivably
result in payment of 100% of allowed claims and possibly provide some payment to
its equity holders. The amounts any plan ultimately distributes to
its various claimants of the Calpine estate, including unsecured creditors, will
depend on the amount of allowed claims that remain following the objection
process. The Bankruptcy Court approved Calpine’s Plan of
Reorganization on December 19, 2007, overruling our objection to the releases
granted by this Plan to prior and current directors and officers of Calpine and
certain of its law firms and other professional advisors.
On August
3, 2007, we executed the PTRA, resolving certain open issues without prejudice
to Calpine’s avoidance action and, if the Court concludes the Purchase Agreement
is executory, Calpine’s ability to assume or reject the Purchase
Agreement. The principal terms are as follows:
|
·
|
We
entered into a new MSA with CPS through and until June 30, 2009, effective
July 1, 2007. This agreement is subject to earlier termination
right by us upon the occurrence of certain
events;
|
|
·
|
Calpine
delivers to us documents that resolve title issues pertaining to the
Properties defined as certain previously purchased oil and gas properties
located in the Gulf of Mexico, California and
Wyoming;
|
|
·
|
We
assume all Calpine's rights and obligations for an audit by the California
State Lands Commission on part of the Properties;
and
|
|
·
|
We
assume all rights and obligations for the Properties, including all
plugging and abandonment
liabilities.
|
On
September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA
did not resolve the open issues on the Non-Consent Properties and certain other
properties.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy, there remains the possibility
that there will be issues between us and Calpine that could amount to material
contingencies in relation to the litigation filed by Calpine against us or the
Purchase Agreement, including unasserted claims and assessments with respect to
(i) 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 PTRA; and (iii) the issues pertaining to the Non-Consent
Properties.
Arbitration
between Calpine/Rosetta and Pogo Producing Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of that sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming that certain leases
subject to the sale had expired because of lack of production. With Rosetta’s
assistance, Calpine had undertaken without success to resolve this matter by
obtaining ratifications of a majority of the questionable leases. Calpine filed
for bankruptcy protection before Pogo filed arbitration against it. Even though
this is a retained liability of Calpine, Calpine had earlier declined to accept
the Company’s tender of defense and indemnity when Pogo filed for arbitration
against us. We filed a motion to stay this arbitration under the
automatic stay provision of the Bankruptcy Code which motion was granted by the
Bankruptcy Court on April 24, 2007. We intend to cooperate with Calpine in
defending against Pogo’s claim should it resume; however, it is too early for
management to determine whether this matter will affect
us, and if so, in what amount. This is due, but not limited to
uncertainity concerning (1) whether or not Pogo’s proofs of claim will be
fully satisfied by Calpine under its approved Plan of Reorganization; and (2)
whether and if so, the extent to which, Calpine may reimburse us for our claim
for our defense costs and any arbitration award regarding the Pogo
claim.
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 2007.
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 2007 and 2006 periods indicated the high and
low sale prices of our common stock:
2007
|
|
|
|
|
|
|
2006
|
|
|
|
|
|
|
|
|
High
|
|
|
Low
|
|
|
|
High
|
|
|
Low
|
|
January 1
- March 31
|
|
$ |
21.07 |
|
|
$ |
17.66 |
|
February 13
- March 31
|
|
$ |
18.75 |
|
|
$ |
17.67 |
|
April 1
- June 30
|
|
|
25.00 |
|
|
|
20.74 |
|
April 1
- June 30
|
|
|
21.48 |
|
|
|
15.81 |
|
July 1
- September 30
|
|
|
21.97 |
|
|
|
15.67 |
|
July 1
- September 30
|
|
|
19.05 |
|
|
|
15.82 |
|
October 1
- December 31
|
|
|
20.84 |
|
|
|
17.69 |
|
October 1
- December 31
|
|
|
19.89 |
|
|
|
16.71 |
|
The
number of shareholders of record on February 18, 2008 was 10,912. 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, 2007:
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
|
|
|
1,404 |
|
|
$ |
18.60 |
|
|
|
- |
|
|
|
- |
|
November
1 - November 30
|
|
|
2,381 |
|
|
|
18.49 |
|
|
|
- |
|
|
|
- |
|
December
1 - December 31
|
|
|
82 |
|
|
|
17.93 |
|
|
|
- |
|
|
|
- |
|
___________________________________
|
(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 stock performance 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 (“HK”), St. Mary Land & Exploration Co. (“SM”),
Bill Barrrett Corp. (“BBG”), Brigham Exploration Co. (“BEXP”), Berry Petroleum
Co. (“BRY”), Comstock Resources Inc. (“CRK”) and Range Resources Corp. (“RRC”),
all known as our peer group (“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.
Total
Return Among Rosetta Resources Inc., the S&P 500 Index and our Peer
Group
|
|
2/13/2006
(1)
|
|
|
12/31/2006
|
|
|
12/31/2007
|
|
ROSE
|
|
$ |
100.00 |
|
|
$ |
98.26 |
|
|
$ |
104.37 |
|
S&P
500 Index
|
|
$ |
100.00 |
|
|
$ |
111.94 |
|
|
$ |
115.89 |
|
Peer
Group
|
|
$ |
100.00 |
|
|
$ |
94.82 |
|
|
$ |
128.62 |
|
___________________________________
(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.
The
following table sets forth our selected financial data. For the years
ended December 31, 2007 and 2006 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 and for the years ended December 31, 2004 and 2003 (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, Statement of Financial Accounting Standards (“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,
|
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
(1)
|
|
|
2003
(1)
|
|
|
|
(In
thousands, except per share data)
|
|
|
|
|
|
|
|
|
|
|
Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenue
|
|
$ |
363,489 |
|
|
$ |
271,763 |
|
|
$ |
113,104 |
|
|
$ |
103,831 |
|
|
$ |
248,006 |
|
|
$ |
279,916 |
|
Income
(loss) from continuing operations (2)
|
|
|
57,205 |
|
|
|
44,608 |
|
|
|
17,535 |
|
|
|
18,681 |
|
|
|
(78,836 |
) |
|
|
66,879 |
|
Net
income (loss) (2)
|
|
|
57,205 |
|
|
|
44,608 |
|
|
|
17,535 |
|
|
|
18,681 |
|
|
|
(10,396 |
) |
|
|
71,440 |
|
Income
per share (2):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.14 |
|
|
|
0.89 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(1.58 |
) |
|
|
1.34 |
|
Diluted
|
|
|
1.13 |
|
|
|
0.88 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(1.58 |
) |
|
|
1.33 |
|
Net
income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
1.14 |
|
|
|
0.89 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(0.21 |
) |
|
|
1.43 |
|
Diluted
|
|
|
1.13 |
|
|
|
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
|
|
|
1,357,214 |
|
|
|
1,219,405 |
|
|
|
1,119,269 |
|
|
|
- |
|
|
|
656,528 |
|
|
|
990,893 |
|
Long-term
debt
|
|
|
245,000 |
|
|
|
240,000 |
|
|
|
240,000 |
|
|
|
- |
|
|
|
- |
|
|
|
507 |
|
Stockholders'
equity/owner's net investment
|
|
|
872,955 |
|
|
|
822,289 |
|
|
|
715,423 |
|
|
|
- |
|
|
|
223,451 |
|
|
|
233,847 |
|
____________________________________
|
(1)
|
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 the
respective periods presented
herein.
|
|
(2)
|
Includes
a $202.1 million pre-tax 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 Rocky Mountains, the Lobo and Perdido Trends
in South Texas, the State Waters of Texas and the Gulf of Mexico 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
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. In addition, we have
also entered into a series of interest rate swap agreements to hedge the change
in variable interest rates associated with our debt under our credit
facility. In periods where interest rates rise, these hedges will
mitigate losses to future earnings. In periods of falling interest
rates, these hedges will expose us to losses in future earnings.
Like all
oil and natural gas exploration and production companies, we face the challenge
of natural production declines. As initial reservoir pressures are depleted, oil
and natural gas production from a given well naturally decreases. Thus, an oil
and natural gas exploration and production company depletes part of its asset
base with each unit of oil or natural gas it produces. We attempt to overcome
this natural decline by drilling and acquiring more reserves than we produce.
Our future growth will depend on our ability to continue to add reserves in
excess of production. We will maintain our focus on adding reserves through
drilling and acquisitions, while placing a clear priority on lowering the
Company’s cost of replacing reserves. Consistent with our stated
strategies, we will emphasize building a high-quality inventory of future
drilling projects while also focusing on improving our capital and cost
efficiency. We have several efforts underway to address this
challenge.
We have
set a goal to fully assess our existing asset portfolio during
2008. We will implement a formal capital performance lookback process
to monitor where value is being created. In addition, we will form
technical teams to study the resource potential of our current assets, many of
which we believe may yield significant future drilling inventory through
down-spacing programs, deeper or shallower programs or close
extensions. The combination of more inventory and calibration on our
programs from the lookback exercise should allow us to deliver better
performance on our future capital spending.
We also
expect to launch several of significant resource assessments in basins,
trends, or plays where significant inventory can be identified. We
are considering several areas where we have technical expertise that could be
applied to new or extension opportunities. This effort will
service existing asset optimization as well as our merger and acquisition
efforts.
Finally,
we will undertake to improve our capital and cost efficiency on an ongoing
business. We will look for opportunities to attract additional
experienced personnel with successful track records, streamline or improve
processes and organize for profitable growth. In addition to the
capital lookback process, we expect to bolster several other core analytic
functions, including reserve engineering, business analysis and
planning.
Financial
Highlights
Our
consolidated financial statements reflect total revenue of $363.5 million on
total volumes of 45.8 Bcfe for the year ended December 31, 2007
(Successor). Operating income was $106.6 million, or 29% of total revenue, and
included lease operating expense of $47.0 million and $6.8 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 long-term debt offset by interest income on short term cash investments.
Overall, our net income for the year ended December 31, 2007 (Successor)
was $57.2 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 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
certain 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. 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. As all of our operations are located in the U.S., all of
our costs are included in one cost pool. 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 directly
relate to our oil and gas activities. Interest costs related to
unproved properties are also capitalized. 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, 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
Netherland Sewell 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. For more
information regarding reserve estimation, including historical reserve
revisions, refer to Item 8. Consolidated Financial Statements and
Supplementary Data, Supplemental Oil and
Gas Disclosures.
Full
Cost Ceiling Limitation
Our
ceiling test computation was calculated using hedge adjusted market prices at
December 31, 2007, which were based on a Henry Hub price of $6.80 per MMBtu and
a West Texas Intermediate oil price of $92.50 per Bbl (adjusted for basis and
quality differentials). The use of these prices would have resulted a pre-tax
writedown of $21.5 million at December 31, 2007. However, we
reevaluated our ceiling test exposure on February 22, 2008 using the
market price for Henry Hub of $8.91 per MMBtu and the price for West Texas
Intermediate $98.88 per Bbl. Utilizing these prices, the
calculated ceiling amount exceeded our net capitalized cost of oil and gas
properties. As a result, no write-down was recorded for the year
ended December 31, 2007. Due to the volatility of commodity prices, should
natural gas prices decline in the future, it is possible that a write-down could
occur.
There was
no ceiling test write-down for the year ended December 31, 2006 or for the six
months ended December 31, 2005.
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 depletion 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
(“DD&A”) rate by approximately $0.18 to $0.19 per MMcfe. This
estimated impact is based on current data at December 31, 2007 and actual events
could require different adjustments to DD&A.
Derivative Transactions and Hedging
Activities
We enter
into derivative transactions to hedge against changes in oil and natural gas
prices and changes in interest rates related to outstanding debt under our
credit agreements primarily through the use of fixed price swap agreements,
basis swap agreements, costless collars and put options. Consistent with our
hedge policy, we entered into a series of derivative transactions to hedge a
significant portion of our expected natural gas production through 2009. We also
entered into a series of interest rate swap agreements to hedge the change in
interest rates associated with our variable rate debt through June of
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 changes
in interest rates 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).
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 and such
costs are included in the calculation of DD&A expense. 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 the property’s 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 DD&A expense.
Likewise, if these estimates are revised downward, earnings would increase due
to lower DD&A expense.
Stock
-Based Compensation
We
account for stock-based compensation in accordance with SFAS 123R. Under the
provisions of SFAS 123R, stock-based compensation cost is estimated at the grant
date based on the award’s fair value as calculated by the Black-Scholes
option-pricing model and is recognized as expense over the requisite service
period. The Black-Scholes model requires various highly judgmental assumptions
including volatility, forfeiture rates and expected option life. If any of the
assumptions used in the Black-Scholes model change significantly, stock-based
compensation expense may differ materially in the future from that recorded in
the current period.
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, 2007 and 2006, 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, natural gas liquids and crude oil 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. 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.
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. Consolidated Financial Statements and Supplementary Data, Note 13 Income
Taxes.
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 $1.0 million for the year ended December 31,
2007.
FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109” (“FIN 48”) requires
that we recognize the financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely than not sustain
the position following an audit. For tax positions meeting the more
likely than not threshold, the amount recognized in the financial statements is
the largest benefit that has a greater than 50% likelihood of being realized
upon ultimate settlement with the relevant tax authority.
Recent
Accounting Developments
Noncontrolling Interests in
Consolidated Financial Statements. In December 2007, the
Financial Accounting Standards Board (“FASB”) issued SFAS No. 160,
“Noncontrolling Interests in Consolidated Financial Statements, an amendment of
Accounting Research Bulletin No. 51” (SFAS No. 160), which improves
the relevance, comparability and transparency of the financial information that
a reporting entity provides in its consolidated financial statements by
establishing accounting and reporting standards for the noncontrolling interest
in a subsidiary and for the deconsolidation of a subsidiary. This
statement is effective for fiscal years beginning after December 15,
2008. We do not expect the adoption of SFAS No. 160 to have a
material impact on our consolidated financial position, results of operations or
cash flows.
Business
Combinations. In December 2007, FASB issued SFAS No. 141(R),
“Business Combinations” (“SFAS No. 141R”), which creates greater consistency in
the accounting and financial reporting of business combinations. This
statement is effective for fiscal years beginning after December 15,
2008. We do not expect the adoption of SFAS No. 141R to have a
material impact on the our consolidated financial position, results of
operations or cash flows.
The Fair Value Option for Financial
Assets and Financial Liabilities. In February 2007, 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. We do not
expect the adoption of SFAS No. 159 to have a material impact on our
consolidated financial position, results of operations or cash flows as we did
not choose to measure at fair value.
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 FASB has also issued
Staff Position FAS 157-2 (“FSP No. 157-2”), which delays the effective date of
SFAS No. 157 for nonfinancial assets and liabilities, except for items that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually), until fiscal years beginning after November 15, 2008.
We do not expect the adoption of SFAS No. 157 or FSP No. 157-2 to have a
material impact on our consolidated financial position, results of operations or
cash flows.
Results
of Operations
The
following table summarizes our results of operations and compares the year ended
December 31, 2007 to the year ended December 31, 2006. However, 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. 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.
Differences
in accounting principles also exist between Calpine and us, 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 for the year ended December 31,
2006 and 2005; therefore, we have presented the information below separately as
Successor and Predecessor. In addition, at the closing of the
Acquisition on July 7, 2005, we retained approximately $75 million of the
purchase price in respect to interest in leases and wells associated with the
Non-Consent Properties. Our operating income does not include our
estimated revenues and expenses related to certain interests in leases and
wells being a portion of the Non-Consent Properties, which were a part
of the Predecessor’s operating income.
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Year
Ended
December
31, 2007
|
|
|
Year
Ended
December
31, 2006
|
|
|
Six
Months Ended
December
31, 2005
|
|
|
Six
Months Ended
June
30, 2005
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenues (In thousands)
|
|
$ |
363,489 |
|
|
$ |
271,763 |
|
|
$ |
113,104 |
|
|
$ |
103,831 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
42.5 |
|
|
|
30.3 |
|
|
|
12.4 |
|
|
|
14.5 |
|
Oil
(MBbls)
|
|
|
561.2 |
|
|
|
551.3 |
|
|
|
185.6 |
|
|
|
163.8 |
|
Total
Equivalents (Bcfe)
|
|
|
45.8 |
|
|
|
33.4 |
|
|
|
13.5 |
|
|
|
15.5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
7.61 |
|
|
$ |
7.81 |
|
|
$ |
8.23 |
|
|
$ |
6.59 |
|
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
7.07 |
|
|
|
6.83 |
|
|
|
9.57 |
|
|
|
- |
|
Avg.
Oil Price per Bbl
|
|
|
71.54 |
|
|
|
64.01 |
|
|
|
59.52 |
|
|
|
49.86 |
|
Avg.
Revenue per Mcfe
|
|
$ |
7.94 |
|
|
$ |
8.14 |
|
|
$ |
8.38 |
|
|
$ |
6.70 |
|
Revenues
Our
revenues are derived from the sale of our oil and natural gas production, which
includes the effects of qualifying commodity hedge contracts. Our
revenues may vary significantly from period to period as a result of changes in
commodity prices or volumes of production sold.
Year
Ended December 31, 2007 (Successor) Compared to the Year Ended December 31, 2006
(Successor)
Total
revenue for the year ended December 31, 2007 was $363.5 million which is an
increase of $91.7 million, or 34%, from the year ended December 31,
2006. Approximately 89% of revenue was attributable to natural gas
sales on total volumes of 45.8 Bcfe.
Natural
Gas. For the year
ended December 31, 2007, natural gas revenue increased by $86.8 million,
including the realized impact of derivative instruments, from the comparable
period in 2006, to $323.3 million. The increase is primarily
attributable to California and Lobo production of 15.9 Bcfe and 14.2 Bcfe,
respectively, or 78% of the increased production. This increase is
primarily due to an increase in the number of wells producing in 2007 as
compared to 2006, which includes the acquisition of the OPEX properties in the
second quarter of 2007. The effect of gas hedging activities on
natural gas revenue for the year ended December 31, 2007 was a gain of $22.9
million as compared to a gain of $29.6 million for the year ended December 31,
2006. The average realized natural gas price including the effects of
hedging decreased from $7.61 per Mcf for the year ended December 31, 2007 as
compared to the same period in 2006 of $7.81 per Mcf.
Crude
Oil. For the year
ended December 31, 2007, oil revenue increased by $4.9 million primarily due to
the increase in the average oil price of $7.53 per Bbl from $64.01 per Bbl for
the year ended December 31, 2006 as compared to $71.54 for the year ended
December 31, 2007. The slight increase in oil production volumes were
associated with increased production in California, Lobo and Texas State Water
regions due to the new wells in 2007.
Year
Ended December 31, 2006 (Successor)
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 including the effects of hedging. 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 an 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
Operating
Expenses
The
following table presents information about our operating expenses:
|
|
Successor-Consolidated
|
|
|
|
|
|
Predecessor-Combined
|
|
|
|
Year
Ended
December
31, 2007
|
|
|
Year
Ended
December
31, 2006
|
|
|
Six
Months Ended
December
31, 2005
|
|
|
Six
Months Ended
June
30, 2005
|
|
|
|
(In
thousands, except per unit amounts)
|
|
|
|
|
Lease
operating expense
|
|
$ |
47,044 |
|
|
$ |
36,273 |
|
|
$ |
15,674 |
|
|
$ |
16,629 |
|
Depreciation,
depletion and amortization
|
|
|
152,882 |
|
|
|
105,886 |
|
|
|
40,500 |
|
|
|
30,679 |
|
Production
taxes
|
|
|
6,417 |
|
|
|
6,433 |
|
|
|
3,975 |
|
|
|
2,755 |
|
General
and administrative costs
|
|
$ |
43,867 |
|
|
$ |
33,233 |
|
|
$ |
14,687 |
|
|
$ |
9,677 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
1.03 |
|
|
$ |
1.09 |
|
|
$ |
1.16 |
|
|
$ |
1.08 |
|
Avg.
DD&A per Mcfe
|
|
|
3.34 |
|
|
|
3.17 |
|
|
|
3.00 |
|
|
|
1.98 |
|
Avg.
production taxes per Mcfe
|
|
|
0.14 |
|
|
|
0.19 |
|
|
|
0.29 |
|
|
|
0.18 |
|
Avg.
G&A per Mcfe
|
|
$ |
0.96 |
|
|
$ |
1.00 |
|
|
$ |
1.09 |
|
|
$ |
0.63 |
|
Year
Ended December 31, 2007 Compared to the Year Ended December 31, 2006
(Successor)
Lease Operating
Expense. Lease operating expense increased $10.8 million for
the year ended December 31, 2007 as compared to the same period for 2006. This
overall increase is primarily due the increase in production of 37% for 2007
which led to higher costs for equipment rentals, maintenance and repairs, and
costs associated with non-operated properties. In addition, there was
an increase of $5.2 million in ad valorem taxes primarily related to property
appraisals in California. The overall increase was offset by a $1.6 million
decrease in workover expense primarily due to the insurance reimbursement in
2007 of $2.4 million for claims submitted as a result of Hurricane Rita. Lease
operating expense includes workover costs of $0.11 per Mcfe, ad valorem taxes of
$0.26 per Mcfe and insurance of $0.05 per Mcfe for the year ended December 31,
2007 as compared to workover costs of $0.19 per Mcfe, ad valorem taxes of $0.20
and insurance of $0.04 per Mcfe for the same period in 2006.
Depreciation, Depletion, and
Amortization. Depreciation, depletion and amortization expense
increased $47.0 million for the year ended December 31, 2007 as compared to the
same period for 2006. The increase is due to a 37% increase in total
production and a higher DD&A rate for 2007 as compared to
2006. The DD&A rate for the respective period in 2007 was $3.34
per Mcfe while the rate for the same period in 2006 was $3.17 per Mcfe due to
the increase in finding costs.
Production
Taxes. Production taxes as a percentage of oil and natural gas
sales were 1.8% for the year ended December 31, 2007 as compared to 2.4% for the
year ended December 31, 2006. This decrease is the result of
increased tax credits received for the year ended December 31, 2007 as compared
to the same period for 2006. The tax credits were received for
natural gas wells drilled in qualifying formations primarily in the Lobo and
Perdido regions.
General and Administrative
Costs. General and administrative costs, net of capitalized
general and administrative costs of $5.5 million for the year ended December 31,
2007, increased by $10.6 million for the year ended December 31, 2007 as
compared to the same period for 2006, with capitalized general and
administrative costs of $3.5 million. This increase is net of
decreases in audit and consulting fees related to higher costs in the first six
months of 2006 associated with becoming a public company, which was not incurred
in 2007. The increase in costs incurred in the current period are
primarily related to increases in the CEO transition costs of approximately $5.0
million, increases in legal fees related to the Calpine litigation of $2.6
million and increases in payroll expenses associated with the payout
of bonuses of $2.9 million. The increase is also associated with
stock-based compensation, which increased $1.1 million from $5.7 million for the
year ended December 31, 2006 to $6.8 million for the year ended December 31,
2007.
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 DD&A rate was $3.17 per Mcfe. There
were no ceiling test write-downs for the year ended December 31,
2006.
Production
Taxes. Production taxes as a percentage of natural gas and oil
sales were approximately 2.4% for the year ended December 31,
2006. Production taxes were primarily based on the wellhead values of
production and vary across the different regions.
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 DD&A 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.
Production
Taxes. Production taxes as a percentage of natural gas and oil
sales were approximately 3.6% for the six months ended December 31,
2005. Production taxes were primarily based on the wellhead values of
production and vary across the different regions.
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 DD&A rate was $1.98 per Mcfe for the six
months ended June 30, 2005.
Production
Taxes. Production taxes as a percentage of natural gas and oil
sales were approximately 2.7% for the six months ended December 31,
2005. Production taxes were primarily based on the wellhead values of
production and vary across the different regions.
General and Administrative
Costs. General and administrative costs for the six months
ended June 30, 2005 were $9.7 million, which is net of capitalized general and
administrative costs of $3.6 million. General and administrative costs are
comprised of items such as salaries and employee benefits, legal fees, and
contract fees. For the six months ended June 30, 2005, of the
$9.7 million in total general and administrative costs, $5.9 million relates to
salary and employee benefits. In addition, $1.3 million are legal
costs and $1.7 million are merger and acquisition costs, which relate to the
sale of the oil and natural gas business to the Company.
Total Other
Expense
Other
expense includes interest expense, interest income and other income/expense, net
which increased $2.5 million for the year ended December 31, 2007 (Successor) as
compared to the respective period in 2006. The increase in other
expense is the result of reduced interest income in 2007 to offset interest
expense as compared to 2006. The interest income is earned on the
cash balances, which were greater during 2006 than in
2007. Approximately $35.3 million was expended during the fourth
quarter of 2006 to fund various asset acquisitions and approximately $38.7
million was expended during the second quarter of 2007 for the acquisition of
the OPEX Properties.
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 Revolver 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 (Predecessor), other expense of $7.0 million was
associated with the intercompany debt with Calpine Corporation.
Provision for Income
Taxes
For the
year ended December 31, 2007(Successor), the effective tax rate was 37.3% as
compared to the effective tax rate of 38.3% for the year ended December 31, 2006
(Successor). For the six months ended December 31, 2005 (Successor),
the effective tax rate was 39.7% and for the six months ended June 30, 2005
(Predecessor), the effective tax rate was 38.1%. The provision for
income taxes differs from the taxes computed at the federal statutory income tax
rate primarily due to the effect of state taxes.
Liquidity
and Capital Resources
Our
primary source of liquidity and capital is our operating cash flow. We also
maintain a revolving line of credit, which can be accessed as needed to
supplement operating cash flow.
Operating Cash
Flow. Our cash flows depend on many factors, including the
price of oil and natural gas and the success of our development and exploration
activities as well as future acquisitions. We actively manage our exposure to
commodity price fluctuations by executing derivative transactions to hedge the
change in prices of our production, thereby mitigating our exposure to price
declines, but these transactions will also limit our earnings potential in
periods of rising natural gas prices. This derivative transaction activity will
allow us the flexibility to continue to execute our capital plan if prices
decline during the period in which our derivative transactions are in place. The
effects of these derivative transactions on our natural gas sales are discussed
above under “Results of Operations – Natural Gas”. In addition, the
majority of our capital expenditures are discretionary and could be curtailed if
our cash flows decline from expected levels.
Senior Secured Revolving Line of
Credit. In July 2005, BNP Paribas provided us with a senior
secured revolving line of credit concurrent with the Acquisition in the amount
of up to $400.0 million (“Revolver”). This Revolver was syndicated to a group of
lenders on September 27, 2005. Availability under the Revolver is
restricted to the borrowing base, which initially was $275.0 million and was
reset to $325.0 million, upon amendment, as a result of the hedges put in place
in July 2005 and the favorable effects of the exercise of the
over-allotment option we granted in our private equity offering in July 2005. In
July 2005, we repaid $60.0 million of the $225.0 million in original borrowings
on the Revolver. In addition, in 2007, we increased our net borrowings against
the Revolver by $5.0 million, bringing the balance to $170.0 million at December
31, 2007. The borrowing base is subject to review and adjustment on a
semi-annual basis and other interim adjustments, including adjustments based on
our hedging arrangements. In May 2007, the borrowing base was adjusted to $350.0
million. Initial amounts outstanding under the Revolver bore
interest, as amended, at specified margins over the London Interbank Offered
Rate (“LIBOR”) of 1.25% to 2.00% (5.82% at December 31, 2007). These
rates over LIBOR were adjusted in May 2007 to be 1.00% to 1.75%. Such
margins will fluctuate based on the utilization of the facility. Borrowings
under the Revolver are collateralized by perfected first priority liens and
security interests on substantially all of our assets, including a mortgage lien
on oil and natural gas properties having at least 80% of the pretax SEC PV-10
reserve value, a guaranty by all of our domestic subsidiaries, a pledge of 100%
of the stock of domestic subsidiaries and a lien on cash securing the Calpine
gas purchase and sale contract. These collateralized amounts under the mortgages
are subject to semi-annual reviews based on updated reserve information. We are
subject to the financial covenants of a minimum current ratio of not less than
1.0 to 1.0 as of the end of each fiscal quarter and a maximum leverage ratio of
not greater than 3.5 to 1.0, calculated at the end of each fiscal quarter for
the four fiscal quarters then ended, measured quarterly with the pro forma
effect of acquisitions and divestitures. At December 31, 2007, our current ratio
was 1.8 to 1.0, as adjusted per current agreements, and our leverage ratio was
0.9 to 1.0. In addition, we are subject to covenants limiting
dividends and other restricted payments, transactions with affiliates,
incurrence of debt, changes of control, asset sales and liens on properties. We
obtained a waiver of any breach of a loan covenant arising out of Calpine’s
institution of Calpine’s fraudulent conveyance action against us and were in
compliance with all covenants at December 31, 2007. All amounts drawn under the
Revolver are due and payable on July 7, 2009. Availability
under the revolving line of credit was $179.0 million at December 31,
2007.
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% (8.82% at
December 31, 2007). The Term Loan is collateralized by second priority liens on
substantially all of our assets. We are subject to the financial covenants of a
minimum asset coverage ratio of not less than 1.5 to 1.0 and a maximum leverage
ratio of not more than 4.0 to 1.0, calculated at the end of each fiscal quarter
for the four fiscal quarters then ended, measured quarterly with the pro forma
effect of acquisitions and divestitures. In addition, we are subject to
covenants limiting dividends and other restricted payments, transactions with
affiliates, incurrence of debt, changes of control, asset sales, and liens on
properties. We obtained a waiver of any breach of a loan covenant arising out of
Calpine’s institution of Calpine’s fraudulent conveyance action against us and
were in compliance with all covenants at December 31, 2007. The revised
principal balance of the Term Loan is due and payable on July 7,
2010.
Our
ability to raise capital depends on the current state of the financial markets,
which are subject to general and economic and industry
conditions. Therefore, the availability of and price of capital in
the financial markets could negatively affect our liquidity position. Our
current liquidity is supported by our revolving credit facility maturing on July
7, 2009.
Working
Capital
At
December 31, 2007, we had a working capital deficit of $62.9 million as compared
to a working capital surplus of $30.7 million at December 31,
2006. 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. This deficit was largely caused by the
decrease in our cash balance to fund capital expenditures, including property
acquisitions as well as an increase in our accrued capital costs. As
of December 31, 2007, the working capital asset balances of our cash and cash
equivalents and derivative instruments were approximately $3.2 million and $4.0
million, respectively, and there was no balance for current deferred tax
assets. In addition, the associated working capital liability
balances for accrued liabilities were approximately $64.2 million as of December
31, 2007.
We
believe we have adequate expected cash flows from operations and available
borrowings under our Revolver to fund our budgeted capital
expenditures.
Cash
Flows
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Year
Ended
December 31,
2007
|
|
|
Year
Ended
December 31,
2006
|
|
|
Six
Months Ended
December 31,
2005
|
|
|
Six
Months Ended
June 30,
2005
|
|
|
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
257,307 |
|
|
$ |
199,610 |
|
|
$ |
63,744 |
|
|
$ |
59,379 |
|
Cash
flows used in investing activities
|
|
|
(322,041 |
) |
|
|
(236,064 |
) |
|
|
(943,246 |
) |
|
|
(30,645 |
) |
Cash
flows provided by (used in) financing activities
|
|
|
5,170 |
|
|
|
(490 |
) |
|
|
979,226 |
|
|
|
(27,239 |
) |
Net
(decrease) increase in cash and cash equivalents
|
|
$ |
(59,564 |
) |
|
$ |
(36,944 |
) |
|
$ |
99,724 |
|
|
$ |
1,495 |
|
Operating Activities. Key
drivers of net cash provided by operating activities are commodity prices,
production volumes and costs and expenses, which primarily include operating
costs, taxes other than income taxes, transportation and general and
administrative expenses. Net cash provided by operating activities
(“Operating Cash Flow”) continued to be a primary source of liquidity and
capital used to finance our capital expenditures for the year ended December 31,
2007.
Cash
flows provided by operating activities increased by $57.7 million for the year
ended December 31, 2007 as compared to the same period for 2006. This increase
is largely affected by our net income, excluding non-cash expenses such as
depreciation, depletion and amortization and deferred income
taxes. For the year ended December 31, 2007, we had net income of
$57.2 million with an increase of production of 37% as compared to the year
ended December 31, 2006 with net income of $44.6 million. As noted
above, we also had a working capital deficit of $62.9 million, which was largely
caused by the decrease in our cash balance to fund capital expenditures,
including property acquisitions. For the year ended December 31,
2007, we incurred approximately $336.1 million in capital expenditures as
compared to $242.2 million for the year ended December 31, 2006.
Net cash
provided by operating activities for the year ended December 31, 2006 was $199.6
million with net income of $44.6 million and 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 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.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities increased by $86.0 million for the year ended
December 31, 2007 as compared to the same period for 2006 and related to our
expenditures for the acquisition of the OPEX properties and drilling and
development of oil and gas properties. During the year ended
December 31, 2007, we participated in the drilling of 195 gross wells as
compared to the drilling of 142 gross wells for the year ended December 31,
2006.
Cash used
in investing activities for the year ended December 31, 2006 was $236.1
million. 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.
Financing
Activities. The primary driver of cash used in financing
activities is equity transactions and issuance and repayments of
debt.
Cash
flows provided by financing activities increased by $5.7 million for the year
ended December 31, 2007 as compared to the same period for 2006. The
net increase is primarily related to net borrowings of $5.0 million made in 2007
against the Revolver. In addition, there were fewer purchases of
treasury stock for the year ended December 31, 2007 than for the comparable
period in 2006. The purchases of stock were surrendered by certain
employees to pay tax withholding upon vesting of restricted stock
awards. These purchases are not part of a publicly announced program
to repurchase shares of our common stock, nor do we have a publicly announced
program to purchase shares of common stock.
Net cash
used in financing activities for the year ended December 31, 2006 was 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.
Commodity
Price Risks 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, basis 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.
We also
entered into a series of basis swaps transactions covering a portion of our 2008
production. The basis swap requires us to pay Natural Gas
Intelligence (“NGI”) PG&E Citygate Index for notional volumes for calendar
year 2008. The counterparty will pay the float price based on the
last trade day settlement of the corresponding forward month contract settlement
of the NYMEX Henry Hub index. When combined with existing NYMEX Henry
Hub fixed price swaps, this effectively creates a fixed price swap that settles
at PG&E Citygate Index. Consistent with our hedge policy the
basis swap transactions will be combined with the NYMEX fixed price swaps noted
above and treated as PG&E fixed price swaps in subsequent
disclosures. See “Item 7A. Quantitative and Qualitative Disclosure
About Market Risk”.
The
following table sets forth the results of commodity hedging transaction
settlements for the year ended December 31, 2007:
|
|
For
the Year Ended
December 31,
2007
|
|
|
For
the Year Ended
December 31,
2006
|
|
Natural
Gas
|
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
23,464,500 |
|
|
|
20,075,000 |
|
Increase
in natural gas sales revenue (In thousands)
|
|
$ |
22,926 |
|
|
$ |
29,578 |
|
Interest
Rate Risks and Related Hedging Activities
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 interest rates. To mitigate this
exposure, we have entered into a series of interest rate swap agreements through
June 2009 to mitigate such risk. If we determine the risk may become substantial
and the costs are not prohibitive, we may enter into additional interest rate
swap agreements in the future.
The
following table sets forth the results of third party interest rate hedging
transactions settled for the year ended December 31, 2007:
|
|
For
the Year Ended
December 31,
2007
|
|
|
For
the Year Ended
December 31,
2006
|
|
Interest
Rate Swaps
|
|
|
|
|
|
|
Decrease
in interest expense (In thousands)
|
|
$ |
20 |
|
|
$ |
- |
|
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 commodity and interest rate hedge positions are with counterparties that
are lenders in our credit facilities. This allows us to secure 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,
2007, we had no deposits for collateral.
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, 2007 were $336.1 million,
and we currently expect to expend approximately $290.1 million during
2008. We believe we have adequate expected cash flows from operations
and available borrowings under our Revolver 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, 2007, the aggregate amounts of our contractually obligated
payment commitments for the next five years are as follows:
|
|
Payments
Due By Period
|
|
|
|
Total
|
|
|
2008
|
|
|
2009
to 2010
|
|
|
2011
to 2012
|
|
|
2013
& Beyond
|
|
|
|
(In
thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Senior
secured revolving line of credit
|
|
$ |
170,000 |
|
|
$ |
- |
|
|
$ |
170,000 |
|
|
$ |
- |
|
|
$ |
- |
|
Second
lien term loan
|
|
|
75,000 |
|
|
|
- |
|
|
|
75,000 |
|
|
|
- |
|
|
|
- |
|
Operating
leases
|
|
|
16,418 |
|
|
|
2,365 |
|
|
|
5,455 |
|
|
|
5,535 |
|
|
|
3,063 |
|
Interest
payments on long-term debt (1)
|
|
|
31,590 |
|
|
|
16,514 |
|
|
|
15,076 |
|
|
|
- |
|
|
|
- |
|
Rig
commitments
|
|
|
4,100 |
|
|
|
4,100 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
contractual obligations
|
|
$ |
297,108 |
|
|
$ |
22,979 |
|
|
$ |
265,531 |
|
|
$ |
5,535 |
|
|
$ |
3,063 |
|
___________________________________
(1)
Future interest payments were calculated based on interest rates and amounts
outstanding at December 31, 2007.
Asset retirement Obligation.
The Company also has liabilities of $22.7 million related to asset retirement
obligations on its Consolidated Balance Sheet at December 31, 2007 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 Item 8. Consolidated Financial Statements and Supplementary Data Note
9, Asset
Retirement Obligation.
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 interests in title to certain domestic oil
and natural gas leases and wells, 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 to such
interests. In July 2005, as part of the transactions undertaken in connection
with closing the Acquisition, we accepted possession of and have since been
operating substantially all of the interests in leases, wells and easements, for
which Calpine retained record legal title. We withheld approximately
$75 million from the aggregate purchase price, which was an agreed dollar amount
under the Purchase Agreement with respect to the Non-Consent
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. 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 continue to be withheld by us
and available 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 and Related Matters
Calpine
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., (“CPS”) which filed for bankruptcy, is providing services to the Company
under a new marketing and services agreement (“MSA”). The initial MSA
was entered into by the Company and Calpine in July 2005 and ran through June
30, 2007. Under a new marketing and service agreement executed in
conjunction with the PTRA, CPS is to provide services through June 30, 2009,
subject to earlier termination by the Company in certain events.
Additionally,
on June 29, 2007, Calpine filed a Lawsuit against us seeking $400 million plus
interest as a result of an alleged shortfall in value received for the assets
involved in the Acquisition, or in the alternative, a return of the domestic oil
and gas assets sold to us by Calpine. We have answered the Lawsuit
and filed our counterclaims.
The
Bankruptcy filing and Lawsuit raises certain concerns regarding aspects of our
relationship with Calpine and certain of its subsidiaries, which we will
continue to closely monitor and, as needed, vigorously protect our
interests. See further discussion of our concerns under Item
1A. Risk Factors and Item 3. Legal Proceedings.
Calpine
and certain of its subsidiaries have since emerged from bankruptcy.
Off-Balance
Sheet Arrangements
At
December 31, 2007 and 2006, 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;
|
·
|
Currency
exchange rates and inflation;
|
·
|
The
availability and cost of relevant raw materials, goods and
services;
|
·
|
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 and
its fraudulent conveyance action, including significant ongoing costs for
lawyers, consultants, experts and all related expenses, as well as all
lost opportunity costs associated with our internal resources dedicated to
these matters and possible impacts on our
reputation;
|
·
|
Disputes
with mineral lease and royalty owners regarding calculation and payment of
royalties;
|
·
|
The
weather, including the occurrence of any adverse weather conditions and/or
natural disasters affecting our business;
and
|
·
|
Any
other factors that impact or could impact the exploration of oil or
natural gas resources, including but not limited to the geology of a
resource, the total amount and costs to develop recoverable reserves,
legal title, regulatory, natural gas administration, marketing and
operational factors relating to the extraction of oil and natural
gas.
|
Item
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, 2007, our annual income before income taxes would change by approximately
$4.3 million for each $0.10 per Mfe change in natural gas prices and
approximately $0.6 million for each $1.00 per Bbl change in crude oil prices,
excluding the effects of hedging.
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, 2007, 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 N
otional
Volume
MMBtu
|
|
|
Average
Underlying
Prices
MMBtu
|
|
|
Total
of Proved
Natural
Gas
Production
Hedged
(1)
|
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2008
|
Swap
|
Cash
Flow
|
|
|
64,909 |
|
|
|
23,756,616 |
|
|
$ |
7.74 |
|
|
|
49 |
% |
|
$ |
2,302 |
|
2009
|
Swap
|
Cash
Flow
|
|
|
42,141 |
|
|
|
15,381,465 |
|
|
|
7.49 |
|
|
|
35 |
% |
|
|
(13,165 |
) |
|
|
|
|
|
|
|
|
|
39,138,081 |
|
|
|
|
|
|
|
|
|
|
$ |
(10,863 |
) |
___________________________________
|
(1)
|
Estimated
based on net gas reserves presented in the December 31, 2007 Netherland,
Sewell & Associates, Inc. reserve
report.
|
In 2008,
we entered into an additional 23,000 MMBtu per day of financial fixed price
swaps covering a portion of our production for 2008 through 2010 at an average
underlying price of $8.27 per MMBtu. We also entered into a series
of costless collars for 10,000 MMBtu per day for a portion of our production in
2008 and 2009 with an average floor price of $8.00 per MMBtu and an average
ceiling price of $10.28 per MMBtu.
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 borrowing base is $350
million and 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 1.00% to 1.75%, 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 due to the repayment of $25 million.
Borrowings under the Term Loan initially bore interest at LIBOR plus
5.00%. The interest rate for the 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 Revolver of $179.0 million as of December 31, 2007.
A one hundred basis point increase in each of the LIBOR rate and federal funds
rate as of December 31, 2007 and 2006 for both our Revolver and Term Loan would
result in an estimated $2.5 million and $2.4 million increase, respectively, in
annual interest expense.
In 2007,
we entered into a series of fixed rate swap agreements for a portion of our
variable rate debt. Our fixed-rate swap agreements are used to fix
the interest rate we pay under our variable rate credit facilities. The
fixed-rate swaps are freestanding financial agreements that require us and the
counterparty to net cash settle our gains and losses on a monthly
basis. Upon settlement, we receive a floating market LIBOR rate and
pay our counterparty a fixed interest rate, as defined in each instrument. When
the floating rate exceeds the fixed rate for a contract month, our counterparty
pays us. When the fixed price exceeds the floating price, we are required to
make a payment to our counterparty. We have designated these swaps as cash flow
hedges.
We have
hedged the interest rates on $75.0 million of our variable rate debt through
2008 and $50.0 million through 2009. As of December 31, 2007 we had
the following financial interest rate swap positions outstanding:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Average
Fixed Rate
|
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2008
|
Swap
|
Cash
Flow
|
|
|
4.41%
|
|
|
$ |
(369 |
) |
2009
|
Swap
|
Cash
Flow
|
|
|
4.55%
|
|
|
|
(282 |
) |
|
|
|
|
|
|
|
|
$ |
(651 |
) |
Derivative
Instruments and Hedging Activities
We use
derivative transactions to manage exposure to changes in commodity prices and
interest rates. 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
interest rate 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
interest rates 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 or variable rate debt and thus provide only partial price protection
against declines in commodity prices or rising interest rates. We expect that
the amount of our derivative contracts will vary from time to time.
Item
8. Financial Statements and Supplementary
Data
Index
to Financial Statements
|
|
Page
|
Reports
of Independent Registered Public Accounting Firm
|
|
50
|
Consolidated
Balance Sheet at December 31, 2007 and 2006
|
|
52
|
Consolidated/Combined
Statement of Operations for the years ended December 31, 2007 and 2006
(Successor), for the six months ended December 31, 2005 (Successor) and
for the six months ended June 30, 2005 (Predecessor)
|
|
53
|
Consolidated/Combined
Statement of Cash Flows for the years ended December 31, 2007 and 2006
(Successor), for the six months ended December 31, 2005 (Successor) and
for the six months ended June 30, 2005 (Predecessor)
|
|
54
|
Consolidated/Combined
Statement of Stockholders' Equity and Comprehensive Income for the years
ended December 31, 2007 and 2006 (Successor) and for the six months ended
December 31, 2005 (Successor), and Changes in Owner's Net Investment for
the six months ended June 30, 2005 (Predecessor)
|
|
55
|
Notes
to Consolidated/Combined Financial Statements
|
|
56
|
Report
of Independent Registered Public Accounting Firm
To the
Board of Directors
and
Stockholders of Rosetta Resources Inc.
In our
opinion, the accompanying consolidated balance sheets and the related
consolidated statements of operations, of cash flows and of stockholders' equity
and comprehensive income present fairly, in all material respects, the financial
position of Rosetta Resources Inc. and its subsidiaries (successor, the
"Company") at December 31, 2007 and 2006, and the results of their operations
and their cash flows for each of the two years in the period ended December 31,
2007 and the six months in the period ended December 31, 2005 in conformity with
accounting principles generally accepted in the United States of
America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31,
2007, based on criteria established in Internal Control - Integrated
Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company's management is responsible
for these financial statements, for maintaining effective internal control over
financial reporting and for its assessment of the effectiveness of internal
control over financial reporting, included in Management's Report on Internal
Control Over Financial Reporting appearing under Item 9A. Our
responsibility is to express opinions on these financial statements and on the
Company's internal control over financial reporting based on our audits (which
was an integrated audit in 2007). We conducted our audits in
accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the financial statements are
free of material misstatement and whether effective internal control over
financial reporting was maintained in all material respects. Our
audits of the financial statements included 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. Our audit of
internal control over financial reporting included obtaining an understanding of
internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk. Our
audits also included performing such other procedures as we considered necessary
in the circumstances. We believe that our audits provide a reasonable basis for
our opinions.
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 a lawsuit against the Company related to the
acquisition of the oil and natural gas business of Calpine Corporation and
Affiliates.
A
company’s internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting
and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles. A company’s internal
control over financial reporting includes those policies and procedures that
(i) pertain to the maintenance of records that, in reasonable detail,
accurately and fairly reflect the transactions and dispositions of the assets of
the company; (ii) provide reasonable assurance that transactions are
recorded as necessary to permit preparation of financial statements in
accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with
authorizations of management and directors of the company; and
(iii) provide reasonable assurance regarding prevention or timely detection
of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because
of its inherent limitations, internal control over financial reporting may not
prevent or detect misstatements. Also, projections of any evaluation
of effectiveness to future periods are subject to the risk that controls may
become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
/s/
PricewaterhouseCoopers LLP
February
29, 2008
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 owner's net
investment for the six months in the period ended June 30, 2005 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, the “Company”) for the six months in the period ended June 30,
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 audit. We
conducted our audit 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 audit provides a reasonable basis for our opinion.
As
described in Note 16 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
Item
8. Financial Statements and Supplementary Data
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
|
|
December
31,
2007
|
|
|
December
31,
2006
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
3,216 |
|
|
$ |
62,780 |
|
Accounts
receivable
|
|
|
55,048 |
|
|
|
36,408 |
|
Derivative
instruments
|
|
|
3,966 |
|
|
|
20,538 |
|
Prepaid
expenses
|
|
|
10,413 |
|
|
|
8,761 |
|
Other
current assets
|
|
|
4,249 |
|
|
|
2,965 |
|
Total
current assets
|
|
|
76,892 |
|
|
|
131,452 |
|
Oil
and natural gas properties, full cost method, of which $40.9 million at
December 31, 2007 and $37.8 million at December 31, 2006 were excluded
from amortization
|
|
|
1,566,082 |
|
|
|
1,223,337 |
|
Other
|
|
|
6,393 |
|
|
|
4,562 |
|
|
|
|
1,572,475 |
|
|
|
1,227,899 |
|
Accumulated
depreciation, depletion, and amortization
|
|
|
(295,749 |
) |
|
|
(145,289 |
) |
Total
property and equipment, net
|
|
|
1,276,726 |
|
|
|
1,082,610 |
|
Deferred
loan fees
|
|
|
2,195 |
|
|
|
3,375 |
|
Other
assets
|
|
|
1,401 |
|
|
|
1,968 |
|
Total
other assets
|
|
|
3,596 |
|
|
|
5,343 |
|
Total
assets
|
|
$ |
1,357,214 |
|
|
$ |
1,219,405 |
|
|
|
|
|
|
|
|
|
|
Liabilities
and Stockholders' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
33,949 |
|
|
$ |
23,040 |
|
Accrued
liabilities
|
|
|
64,216 |
|
|
|
43,099 |
|
Royalties
payable
|
|
|
18,486 |
|
|
|
9,010 |
|
Derivative
instruments
|
|
|
2,032 |
|
|
|
- |
|
Prepayment
on gas sales
|
|
|
20,392 |
|
|
|
17,868 |
|
Deferred
income taxes
|
|
|
720 |
|
|
|
7,743 |
|
Total
current liabilities
|
|
|
139,795 |
|
|
|
100,760 |
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
13,508 |
|
|
|
11,014 |
|
Long-term
debt
|
|
|
245,000 |
|
|
|
240,000 |
|
Asset
retirement obligation
|
|
|
18,040 |
|
|
|
10,253 |
|
Deferred
income taxes
|
|
|
67,916 |
|
|
|
35,089 |
|
Total
liabilities
|
|
|
484,259 |
|
|
|
397,116 |
|
Commitments
and contingencies (Note 11)
|
|
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in
2007 or 2006
|
|
|
- |
|
|
|
- |
|
Common
stock, $0.001 par value; authorized 150,000,000 shares; issued 50,542,648
shares and 50,405,794 shares at December 31, 2007 and December 31, 2006,
respectively
|
|
|
50 |
|
|
|
50 |
|
Additional
paid-in capital
|
|
|
762,827 |
|
|
|
755,343 |
|
Treasury
stock, at cost; 109,303 shares and 85,788 shares at December 31, 2007 and
December
31, 2006, respectively
|
|
|
(2,045 |
) |
|
|
(1,562 |
) |
Accumulated
other comprehensive (loss) income
|
|
|
(7,225 |
) |
|
|
6,315 |
|
Retained
earnings
|
|
|
119,348 |
|
|
|
62,143 |
|
Total
stockholders' equity
|
|
|
872,955 |
|
|
|
822,289 |
|
Total
liabilities and stockholders' equity
|
|
$ |
1,357,214 |
|
|
$ |
1,219,405 |
|
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, 2007
|
|
|
Year
Ended
December
31, 2006
|
|
|
Six
Months Ended
December
31,
2005
|
|
|
Six
Months Ended
June
30,
2005
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural
gas sales
|
|
$ |
323,341 |
|
|
$ |
236,496 |
|
|
$ |
102,058 |
|
|
$ |
13,713 |
|
Oil
sales
|
|
|
40,148 |
|
|
|
35,267 |
|
|
|
11,046 |
|
|
|
8,166 |
|
Oil
and natural gas sales to affiliates
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
81,952 |
|
Total
revenues
|
|
|
363,489 |
|
|
|
271,763 |
|
|
|
113,104 |
|
|
|
103,831 |
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
|
47,044 |
|
|
|
36,273 |
|
|
|
15,674 |
|
|
|
16,629 |
|
Depreciation,
depletion, and amortization
|
|
|
152,882 |
|
|
|
105,886 |
|
|
|
40,500 |
|
|
|
30,679 |
|
Exploration
expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
2,355 |
|
Dry
hole costs
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,962 |
|
Treating
and transportation
|
|
|
4,230 |
|
|
|
2,544 |
|
|
|
1,286 |
|
|
|
1,998 |
|
Affiliated
marketing fees
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
913 |
|
Marketing
fees
|
|
|
2,450 |
|
|
|
2,257 |
|
|
|
1,379 |
|
|
|
- |
|
Production
taxes
|
|
|
6,417 |
|
|
|
6,433 |
|
|
|
3,975 |
|
|
|
2,755 |
|
General
and administrative costs
|
|
|
43,867 |
|
|
|
33,233 |
|
|
|
14,687 |
|
|
|
9,677 |
|
Total
operating costs and expenses
|
|
|
256,890 |
|
|
|
186,626 |
|
|
|
77,501 |
|
|
|
66,968 |
|
Operating
income
|
|
|
106,599 |
|
|
|
85,137 |
|
|
|
35,603 |
|
|
|
36,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
(income) expense
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense with affiliates, net of interest capitalized
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,995 |
|
Interest
expense, net of interest capitalized
|
|
|
17,734 |
|
|
|
17,428 |
|
|
|
8,216 |
|
|
|
- |
|
Interest
income
|
|
|
(1,674 |
) |
|
|
(4,503 |
) |
|
|
(1,837 |
) |
|
|
(516 |
) |
Other
(income) expense, net
|
|
|
(698 |
) |
|
|
(40 |
) |
|
|
152 |
|
|
|
207 |
|
Total
other expense
|
|
|
15,362 |
|
|
|
12,885 |
|
|
|
6,531 |
|
|
|
6,686 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
before provision for income taxes
|
|
|
91,237 |
|
|
|
72,252 |
|
|
|
29,072 |
|
|
|
30,177 |
|
Provision
for income taxes
|
|
|
34,032 |
|
|
|
27,644 |
|
|
|
11,537 |
|
|
|
11,496 |
|
Net
income
|
|
$ |
57,205 |
|
|
$ |
44,608 |
|
|
$ |
17,535 |
|
|
$ |
18,681 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
1.14 |
|
|
$ |
0.89 |
|
|
$ |
0.35 |
|
|
$ |
0.37 |
|
Diluted
|
|
$ |
1.13 |
|
|
$ |
0.88 |
|
|
$ |
0.35 |
|
|
$ |
0.37 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
50,379 |
|
|
|
50,237 |
|
|
|
50,003 |
|
|
|
50,000 |
|
Diluted
|
|
|
50,589 |
|
|
|
50,408 |
|
|
|
50,189 |
|
|
|
50,160 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated/Combined
Statement of Cash Flows
(In
thousands)
|
|
Successor-Consolidated
|
|
|
Predecessor-Combined
|
|
|
|
Year
Ended
December
31, 2007
|
|
|
Year
Ended
December
31, 2006
|
|
|
Six
Months Ended
December
31, 2005
|
|
|
Six
Months Ended
June
30, 2005
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
income
|
|
|
57,205 |
|
|
|
44,608 |
|
|
|
17,535 |
|
|
|
18,681 |
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
152,882 |
|
|
|
105,886 |
|
|
|
40,500 |
|
|
|
30,679 |
|
Affiliate
interest expense
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(6,995 |
) |
Deferred
income taxes
|
|
|
33,915 |
|
|
|
27,472 |
|
|
|
11,537 |
|
|
|
2,874 |
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
1,180 |
|
|
|
1,180 |
|
|
|
590 |
|
|
|
- |
|
Stock
compensation expense
|
|
|
6,831 |
|
|
|
5,702 |
|
|
|
4,248 |
|
|
|
- |
|
Other
non-cash charges
|
|
|
(181 |
) |
|
|
(171 |
) |
|
|
(241 |
) |
|
|
(62 |
) |
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
(18,640 |
) |
|
|
3,643 |
|
|
|
(40,051 |
) |
|
|
2,378 |
|
Accounts
receivable from affiliates
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,298 |
|
Income
taxes receivable
|
|
|
- |
|
|
|
6,000 |
|
|
|
(6,000 |
) |
|
|
- |
|
Prepaid
expenses
|
|
|
(1,652 |
) |
|
|
650 |
|
|
|
(9,411 |
) |
|
|
2,563 |
|
Other
current assets
|
|
|
(1,284 |
) |
|
|
(2,965 |
) |
|
|
- |
|
|
|
- |
|
Other
assets
|
|
|
144 |
|
|
|
1,691 |
|
|
|
(1,726 |
) |
|
|
- |
|
Accounts
payable
|
|
|
10,909 |
|
|
|
8,765 |
|
|
|
13,442 |
|
|
|
(4,494 |
) |
Accrued
liabilities
|
|
|
3,998 |
|
|
|
310 |
|
|
|
3,282 |
|
|
|
241 |
|
Royalties
payable
|
|
|
12,000 |
|
|
|
(3,161 |
) |
|
|
30,039 |
|
|
|
(1,406 |
) |
Income
taxes payable
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,622 |
|
Net
cash provided by operating activities
|
|
|
257,307 |
|
|
|
199,610 |
|
|
|
63,744 |
|
|
|
59,379 |
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition
of Calpine, net of cash acquired
|
|
|
- |
|
|
|
- |
|
|
|
(910,064 |
) |
|
|
- |
|
Acquisition
of oil and gas properties
|
|
|
(38,656 |
) |
|
|
(35,286 |
) |
|
|
- |
|
|
|
- |
|
Purchases
of property and equipment
|
|
|
(284,541 |
) |
|
|
(201,293 |
) |
|
|
(32,994 |
) |
|
|
(32,202 |
) |
Disposals
of property and equipment
|
|
|
1,105 |
|
|
|
30 |
|
|
|
13 |
|
|
|
1,447 |
|
Other
|
|
|
51 |
|
|
|
485 |
|
|
|
(201 |
) |
|
|
110 |
|
Net
cash used in investing activities
|
|
|
(322,041 |
) |
|
|
(236,064 |
) |
|
|
(943,246 |
) |
|
|
(30,645 |
) |
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
|
|
|
10,000 |
|
|
|
- |
|
|
|
225,000 |
|
|
|
- |
|
Payments
on revolving credit facility
|
|
|
(5,000 |
) |
|
|
- |
|
|
|
(60,000 |
) |
|
|
- |
|
Loan
fees
|
|
|
- |
|
|
|
- |
|
|
|
(5,145 |
) |
|
|
- |
|
Notes
payable to affiliates
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(27,239 |
) |
Proceeds
from issuances of common stock
|
|
|
653 |
|
|
|
804 |
|
|
|
- |
|
|
|
- |
|
Purchases
of treasury stock
|
|
|
(483 |
) |
|
|
(1,562 |
) |
|
|
- |
|
|
|
- |
|
Net
cash provided by (used in) financing activities
|
|
|
5,170 |
|
|
|
(490 |
) |
|
|
979,226 |
|
|
|
(27,239 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
(decrease) increase in cash
|
|
|
(59,564 |
) |
|
|
(36,944 |
) |
|
|
99,724 |
|
|
|
1,495 |
|
Cash
and cash equivalents, beginning of period
|
|
|
62,780 |
|
|
|
99,724 |
|
|
|
- |
|
|
|
- |
|
Cash
and cash equivalents, end of period
|
|
$ |
3,216 |
|
|
$ |
62,780 |
|
|
$ |
99,724 |
|
|
$ |
1,495 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest expense, net of capitalized Interest
|
|
$ |
18,862 |
|
|
$ |
17,875 |
|
|
$ |
(8,057 |
) |
|
$ |
- |
|
Cash
paid for tax
|
|
$ |
115 |
|
|
$ |
172 |
|
|
$ |
6,000 |
|
|
$ |
- |
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures included in accrued liabilities
|
|
$ |
12,925 |
|
|
$ |
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 Changes in Stockholders’ Equity and Changes in Owner’s Net
Investment
(In
thousands, except share amounts)
|
|
Common
Stock
|
|
|
Additional
|
|
|
Treasury
Stock
|
|
|
Accumulated
Other
|
|
|
|
|
|
Total
Stockholders'
Equity
&
|
|
Predecessor
|
|
Shares
|
|
|
Amount
|
|
|
Paid-In
Capital
|
|
|
Shares
|
|
|
Amount
|
|
|
Comprehensive
(Loss)/Income
|
|
|
Retained
Earnings
|
|
|
Owner's
Net Investment
|
|
Balance
January 1, 2005
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
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
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
options exercised
|
|
|
49,896 |
|
|
|
- |
|
|
|
804 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
804 |
|
Treasury
stock - employee tax payment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
85,788 |
|
|
|
(1,562 |
) |
|
|
- |
|
|
|
- |
|
|
|
(1,562 |
) |
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
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) related to cash flow hedges
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(34,916 |
) |
|
|
- |
|
|
|
(34,916 |
) |
Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
101,654 |
|
Balance
December 31, 2006
|
|
|
50,405,794 |
|
|
$ |
50 |
|
|
$ |
755,343 |
|
|
|
85,788 |
|
|
$ |
(1,562 |
) |
|
$ |
6,315 |
|
|
$ |
62,143 |
|
|
$ |
822,289 |
|
Stock
options exercised
|
|
|
40,104 |
|
|
|
- |
|
|
|
653 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
653 |
|
Treasury
stock - employee tax payment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
23,515 |
|
|
|
(483 |
) |
|
|
- |
|
|
|
- |
|
|
|
(483 |
) |
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
6,831 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
6,831 |
|
Vesting
of restricted stock
|
|
|
96,750 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Comprehensive
Income:
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
57,205 |
|
|
|
57,205 |
|
Change
in fair value of derivative hedging instruments
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
1,276 |
|
|
|
- |
|
|
|
1,276 |
|
Hedge
settlements reclassified to income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(22,926 |
) |
|
|
- |
|
|
|
(22,926 |
) |
Tax
benefit related to cash flow hedges
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
8,110 |
|
|
|
- |
|
|
|
8,110 |
|
Comprehensive
Income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
|
|
- |
|
|
|
43,665 |
|
Balance
December 31, 2007
|
|
|
50,542,648 |
|
|
|
50 |
|
|
|
762,827 |
|
|
|
109,303 |
|
|
|
(2,045 |
) |
|
|
(7,225 |
) |
|
|
119,348 |
|
|
$ |
872,955 |
|
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., its partners, and 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”) and
Rosetta Resources California, LLC, Rosetta Resources Rockies, LLC, Rosetta
Resources Offshore, LLC and Rosetta Resources Texas LP and its partners in July
2005 (hereinafter, the “Acquisition”) and, together with all subsequently
acquired oil and natural gas properties, is engaged in oil and natural gas
exploration, development, production and acquisition activities in the United
States. The Company’s main operations are primarily concentrated in the
Sacramento Basin of California, the Rocky Mountains, the Lobo and Perdido Trends
in South Texas, the State Waters of Texas and the Gulf of Mexico.
Certain
reclassifications of prior year balances have been made to conform such amounts
to corresponding 2007 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
interests in certain leases and wells associated with the non-consent properties
described in Note 11 pertaining to the Calpine bankruptcy, 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. For additional information
see Note 11 to the Consolidated/Combined Financial Statements.
The
unaudited pro forma information below for the year ended December 31, 2005
assumes the acquisition of Calpine’s domestic oil and natural gas business and
the related financings occurred at the beginning of the period
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
|
|
|
|
(In
thousands,
except
per share amounts)
|
|
|
|
(Unaudited)
|
|
Revenues
|
|
$ |
207,501 |
|
Net
income
|
|
|
26,437 |
|
Basic
earnings per common share
|
|
|
0.53 |
|
Diluted
earnings per common share
|
|
$ |
0.53 |
|
(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
accompanying consolidated financial statements for the years ended December 31,
2007 and 2006 and for the six months ended December 31, 2005 contain the
accounts of Rosetta Resources Inc. and its majority owned subsidiaries after
eliminating all significant intercompany balances and transactions.
The
Predecessor combined financial statements for the six months ended June 30, 2005
have been prepared from the historical accounting records of the domestic oil
and natural gas business of Calpine and are presented on a carve-out basis to
include the historical operations of the domestic oil and natural gas
business. The domestic oil and natural gas business of Calpine
was separately accounted for and managed through direct and indirect
subsidiaries of Calpine. The combined financial information included herein
includes certain allocations based on the historical activity levels to reflect
the combined financial statements in accordance with accounting principles
generally accepted in the United States of America and may not necessarily
reflect the financial position, results of operations and cash flows of the
Company in the future or as if the Company had existed as a separate,
stand-alone business during the period presented. The allocations consist of
general and administrative expenses such as employee payroll and related benefit
costs and building lease expense, which were incurred on behalf of Calpine. The
allocations have been made on a reasonable basis and have been consistently
applied for the periods presented.
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 including uncertain tax positions, the outcome of pending
litigation, stock-based compensation, 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.
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, including salaries, benefits and
other internal costs directly attributable to these activities, are capitalized
when incurred into cost centers that are established on a country-by-country
basis, 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, unevaluated properties and significant
development projects 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 $5.5 million and $3.4 million of
internal costs for the years ended December 31, 2007 and 2006,
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 or reserves are sold.
The
Company assesses the impairment for oil and natural gas properties quarterly
using a ceiling test to determine if impairment is necessary. If the
net capitalized costs of oil and natural gas properties exceed the cost center
ceiling, the Company is subject to a ceiling test write-down to the extent of
such excess. A ceiling test write-down is a charge to earnings and
cannot be reinstated even if the cost ceiling increases at a subsequent
reporting date. If required, it would reduce earnings and impact
shareholders’ equity in the period of occurrence and result in a lower
depreciation, depletion and amortization expense in the future.
The
Company’s ceiling test computation was calculated using hedge adjusted market
prices at December 31, 2007, which were based on a Henry Hub price of $6.80 per
MMBtu and a West Texas Intermediate oil price of $92.50 per Bbl (adjusted for
basis and quality differentials). The use of these prices would have resulted in
a pre-tax writedown of $21.5 million at December 31,
2007. However, we
reevaluated our ceiling test exposure on February 22, 2008 using the
market price for Henry Hub of $8.91 per MMBtu and the price for West Texas
Intermediate of $98.88 per Bbl. Utilizing these prices, the
calculated ceiling amount exceeded our net capitalized cost of oil and gas
properties. As a result, no write-down was recorded for the year
ended December 31, 2007. Due to the volatility of commodity prices, should
natural gas prices decline in the future, it is possible that a write-down could
occur.
No
impairment charge was recorded for the year ended December 31, 2006 or 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. 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 related to
unevaluated properties and significant development projects in accordance with
SFAS No. 34, “Capitalization of Interest Cost,” (“SFAS
No. 34”). As proved reserves are established or impairment
determined, the related capitalized interest is included in costs subject to
amortization.
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. Derivatives are also recorded on
the balance sheet at fair market value. As of December 31, 2007 and 2006,
the carrying value of our debt was approximately $245 million and $240 million,
respectively. 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.
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.
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 the term of the related debt using
the straight-line method, which approximates the effective interest
method.
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 also
uses derivatives to manage interest rate risk associated with its debt under its
credit facility. 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 or interest rate and a variable price or LIBOR rate for a
fixed notional quantity or amount 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 or debt under its current credit agreements.
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 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.
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, and such
costs are included in the calculation of DD&A expense. 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.
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. There were no significant
environmental liabilities at December 31, 2007 or 2006.
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.
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 $0.1 million of related excess tax
benefits which will be recognized upon utilization of our net operating loss
carryforward.
Preferred
Stock
The
Company is authorized to issue 5,000,000 shares of preferred stock with
preferences and rights as determined by the Company’s Board of
Directors. As of December 31, 2007 and 2006, there were no shares
outstanding.
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.
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, 2007 and 2006, 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, natural gas liquids and crude oil 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. 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.
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.
FASB
Interpretation No. 48, “Accounting for Uncertainty in Income Taxes - an
interpretation of FASB Statement No. 109” (“FIN 48”) requires
that we recognize the financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely than not sustain
the position following an audit. For tax positions meeting the more
likely than not threshold, the amount recognized in the financial statements is
the largest benefit that has a greater than 50% likelihood of being realized
upon ultimate settlement with the relevant tax authority.
Recent
Accounting Developments
Noncontrolling Interests in
Consolidated Financial Statements. In December 2007, the
Financial Accounting Standards Board (“FASB”) issued SFAS No. 160,
“Noncontrolling Interests in Consolidated Financial Statements, an amendment of
Accounting Research Bulletin No. 51” (SFAS No. 160), which improves
the relevance, comparability and transparency of the financial information that
a reporting entity provides in its consolidated financial statements by
establishing accounting and reporting standards for the noncontrolling interest
in a subsidiary and for the deconsolidation of a subsidiary. This
statement is effective for fiscal years beginning after December 15,
2008. The Company does not expect the adoption of SFAS No. 160 to
have a material impact on the Company’s consolidated financial position, results
of operations or cash flows.
Business
Combinations. In December 2007, FASB issued SFAS No. 141(R),
“Business Combinations” (“SFAS No. 141R”), which creates greater consistency in
the accounting and financial reporting of business combinations. This
statement is effective for fiscal years beginning after December 15,
2008. The Company does not expect the adoption of SFAS No. 141R
to have a material impact on the Company’s consolidated financial position,
results of operations or cash flows.
The Fair Value Option for Financial
Assets and Financial Liabilities. In February 2007, 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 does not expect
the adoption of SFAS No. 159 to have a material impact on the Company’s
consolidated financial position, results of operations or cash flows as the
Company did not choose to measure at fair value.
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 FASB has also issued Staff
Position FAS 157-2 (“FSP No. 157-2”), which delays the effective date of SFAS
No. 157 for nonfinancial assets and liabilities, except for items that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually), until fiscal years beginning after November 15,
2008. The Company does not expect the adoption of SFAS No. 157 or FSP
No. 157-2 to have a material impact on the Company’s consolidated financial
position, results of operations or cash flows.
Accounts
receivable consisted of the following:
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Natural
gas, NGLs and oil revenue sales
|
|
$ |
46,376 |
|
|
$ |
34,027 |
|
Joint
interest billings
|
|
|
7,750 |
|
|
|
959 |
|
Short-term
receivable for royalty recoupment
|
|
|
922 |
|
|
|
1,422 |
|
Total
|
|
|
55,048 |
|
|
|
36,408 |
|
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, 2007 and
December 31, 2006.
(5)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,499,046 |
|
|
$ |
1,167,588 |
|
Unproved/unevaluated
properties
|
|
|
40,903 |
|
|
|
37,813 |
|
Gas
gathering system and compressor station
|
|
|
26,133 |
|
|
|
17,936 |
|
Other
|
|
|
6,393 |
|
|
|
4,562 |
|
Total
|
|
|
1,572,475 |
|
|
|
1,227,899 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(295,749 |
) |
|
|
(145,289 |
) |
|
|
$ |
1,276,726 |
|
|
$ |
1,082,610 |
|
Included
in the Company’s oil and natural gas properties are asset retirement costs of
$20.1 million and $9.6 million at December 31, 2007 and 2006, respectively,
including additions of $2.1 million and $0.5 million for the year ended December
31, 2007 and 2006, respectively.
At
December 31, 2007 and 2006, the Company excluded the following capitalized costs
from depreciation, depletion and amortization:
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Onshore:
|
|
(In
thousands)
|
|
Development
cost
|
|
|
|
|
|
|
Incurred
in 2007
|
|
$ |
591 |
|
|
$ |
- |
|
Incurred
in 2006
|
|
|
- |
|
|
|
- |
|
Incurred
in 2005
|
|
|
- |
|
|
|
- |
|
Exploration
cost
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
5,650 |
|
|
|
- |
|
Incurred
in 2006
|
|
|
- |
|
|
|
2,635 |
|
Incurred
in 2005
|
|
|
- |
|
|
|
- |
|
Acquisition
cost of undeveloped acreage
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
9,023 |
|
|
|
- |
|
Incurred
in 2006
|
|
|
7,568 |
|
|
|
9,976 |
|
Incurred
in 2005
|
|
|
8,404 |
|
|
|
16,978 |
|
Capitalized
interest
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
2,026 |
|
|
|
- |
|
Incurred
in 2006
|
|
|
999 |
|
|
|
1,925 |
|
Incurred
in 2005
|
|
|
36 |
|
|
|
228 |
|
Total
|
|
|
34,297 |
|
|
|
31,742 |
|
|
|
|
|
|
|
|
|
|
Offshore:
|
|
|
|
|
|
|
|
|
Exploration
cost
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
- |
|
|
|
- |
|
Incurred
in 2006
|
|
|
- |
|
|
|
- |
|
Incurred
in 2005
|
|
|
- |
|
|
|
- |
|
Acquisition
cost of undeveloped acreage
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
209 |
|
|
|
- |
|
Incurred
in 2006
|
|
|
5,860 |
|
|
|
5,860 |
|
Incurred
in 2005
|
|
|
- |
|
|
|
- |
|
Capitalized
interest
|
|
|
|
|
|
|
|
|
Incurred
in 2007
|
|
|
381 |
|
|
|
- |
|
Incurred
in 2006
|
|
|
150 |
|
|
|
184 |
|
Incurred
in 2005
|
|
|
6 |
|
|
|
27 |
|
Total
|
|
|
6,606 |
|
|
|
6,071 |
|
|
|
|
|
|
|
|
|
|
Total
costs excluded from depreciation, depletion, and
amortization
|
|
$ |
40,903 |
|
|
$ |
37,813 |
|
It is
anticipated that the acquisition of undeveloped acreage and associated
capitalized interest of $34.7 million and development and exploration costs of
$6.2 million will be included in depreciation, depletion and amortization within
five years and one year, respectively.
Property
Acquisitions. During the second quarter of 2007, the Company
acquired properties located in the Sacramento Basin from Output Exploration ,
LLC and OPEX Energy, LLC at a total purchase price of $38.7
million.
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 System and compressor
station. The gas gathering system and compressor station of $26.1 million
and $17.9 million at December 31, 2007 and 2006, respectively, is located in
California and the Rocky Mountains. The gas gathering system and
compressor station are recorded at cost and depreciated on a straight-line basis
over useful lives of 15 years. The accumulated depreciation for the
gas gathering system at December 31, 2007 and 2006 was $3.0 million and $1.5
million, respectively. The depreciation expense associated with the
gas gathering system and compressor station for the years ended December 31,
2007 and 2006 (Successor), six months ended December 31, 2005 (Successor) and
the six months ended June 30, 2005 (Predecessor) was $1.5 million, $1.0 million,
$0.5 million and $0.6 million, respectively.
Other Property and Equipment.
Other property and equipment at December 31, 2007 and 2006 of $6.4 million and
$4.6 million, respectively, consists primarily of furniture and
fixtures. The accumulated depreciation associated with other assets
at December 31, 2007 and 2006 was $1.4 million and $0.6 million,
respectively. For the years ended December 31, 2007 and 2006
(Successor), six months ended December 31, 2005 (Successor) and six months
ended June 30, 2005 (Predecessor), depreciation expense for other property and
equipment was $0.8 million, $0.5 million, $0.1 million and $0.4 million,
respectively.
At
December 31, 2007 and 2006, deferred loan fees were $2.2 million and $3.4
million, respectively. Total amortization expense for deferred loan fees was
$1.2 million for the years ended December 31, 2007 and 2006, respectively, and
$0.6 million for the six months ended December 31, 2005.
(7)
|
Commodity
Hedging Contracts and Other
Derivatives
|
The
Company entered into a series of basis swaps transactions covering a portion of
the Company’s 2007 and 2008 production. The basis swap requires the
Company to pay Natural Gas Intelligence (“NGI”) PG&E Citygate Index for
notional volumes for calendar year 2008. The counterparty pays the
float price based on the last trade day settlement of the corresponding forward
month contract settlement of the NYMEX Henry Hub index. When combined
with existing NYMEX Henry Hub fixed price swaps, this effectively creates a
fixed price swap that settles at PG&E Citygate Index. Consistent
with our hedge policy, the basis swap transactions were combined with the NYMEX
fixed price swaps and treated as PG&E fixed price swaps. The
combined fixed price swap is included in the financial fixed price swaps
positions noted below.
The
Company has entered into financial fixed price swaps with prices ranging from
$6.81 per MMBtu to $8.63 per MMBtu covering a portion of the Company’s 2008 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, 2007:
Settlement
Period
|
|
Derivative
Instrument
|
|
Hedge
Strategy
|
|
Notional
Daily
Volume
MMBtu
|
|
|
Total
of
Notional
Volume
MMBtu
|
|
|
Average
Underlying
Prices
MMBtu
|
|
|
Total
of Proved
Natural
Gas
Production
Hedged
(1)
|
|
|
Fair
Market
Value
Gain/(Loss)
(In
thousands)
|
|
2008
|
|
Swap
|
|
Cash
Flow
|
|
64,909
|
|
|
|
23,756,616 |
|
|
$
|
7.74
|
|
|
|
49%
|
|
|
$ |
2,302 |
|
2009
|
|
Swap
|
|
Cash
Flow
|
|
42,141
|
|
|
|
15,381,465 |
|
|
|
7.49
|
|
|
|
35%
|
|
|
|
(13,165 |
) |
|
|
|
|
|
|
|
|
|
|
39,138,081 |
|
|
|
|
|
|
|
|
|
|
$ |
(10,863 |
) |
(1)
Estimated based on net gas reserves presented in the December 31, 2007
Netherland, Sewell, & Associates, Inc. reserve report.
The
Company has hedged the interest rates on $75.0 million of its
outstanding debt through 2008 and $50.0 million through 2009. As
of December 31, 2007, the Company had the following financial interest rate swap
positions outstanding:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Average
Fixed Rate
|
|
|
Fair
Market
Value
Gain/(Loss)
(In
thousands)
|
|
2008
|
Swap
|
Cash
Flow
|
|
|
4.41%
|
|
|
$ |
(369 |
) |
2009
|
Swap
|
Cash
Flow
|
|
|
4.55%
|
|
|
|
(282 |
) |
|
|
|
|
|
|
|
|
$ |
(651 |
) |
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, 2007, the Company made no deposits
for collateral.
The
following table sets forth the results of hedge transaction settlements for the
respective period for the Consolidated Statement of Operations:
|
|
For
the Year Ended
December 31,
2007
|
|
|
For
the Year Ended
December 31,
2006
|
|
Natural
Gas
|
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
23,464,500 |
|
|
|
20,075,000 |
|
Increase
in natural gas sales revenue (In thousands)
|
|
$ |
22,926 |
|
|
$ |
29,578 |
|
The
following table sets forth the results of third party interest rate hedging
transactions settled for the Consolidated Statement of Operations:
|
|
For
the Year Ended
December 31,
2007
|
|
|
For
the Year Ended
December 31,
2006
|
|
Interest
Rate Swaps
|
|
|
|
|
|
|
Decrease
in interest expense (In thousands)
|
|
$ |
20 |
|
|
$ |
- |
|
The
Company expects to reclassify gains of $1.2 million based on market pricing as
of December 31, 2007 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the next
twelve months.
At
December 2007, the Company had derivative assets of $4.0 million, of which $0.1
million is included in other assets on the Consolidated Balance
Sheet. The Company also had derivative liabilities of $15.5 million,
of which $2.0 million is included in current liabilities on the Consolidated
Balance Sheet at December 31, 2007.
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, 2007 and 2006.
In 2008,
the Company entered into an additional 23,000 MMBtu per day of financial fixed
price swaps covering a portion of the Company’s production for 2008 through 2010
at an average underlying price of $8.27 per MMBtu. The Company also
entered into a series of costless collars for 10,000 MMBtu per day for a portion
of the Company’s production in 2008 and 2009 with an average floor price of
$8.00 per MMBtu and an average ceiling price of $10.28 per MMBtu.
The
Company’s accrued liabilities consists of the following:
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Accrued
capital costs
|
|
$ |
34,599 |
|
|
$ |
21,674 |
|
Accrued
purchase price adjustments
|
|
|
11,400 |
|
|
|
11,400 |
|
Accrued
payroll and employee incentive expense
|
|
|
5,361 |
|
|
|
3,028 |
|
Accrued
lease operating expense
|
|
|
4,930 |
|
|
|
5,252 |
|
Asset
Retirement Obligation
|
|
|
4,629 |
|
|
|
435 |
|
Other
|
|
|
3,297 |
|
|
|
1,310 |
|
Total
|
|
$ |
64,216 |
|
|
$ |
43,099 |
|
(9)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
For
the Year Ended December 31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
ARO
as of the beginning of the period
|
|
$ |
10,689 |
|
|
$ |
9,467 |
|
Revision
of previous estimate
|
|
|
9,751 |
|
|
|
- |
|
Liabilities
incurred during period
|
|
|
2,105 |
|
|
|
467 |
|
Liabilities
settled during period
|
|
|
(1,355 |
) |
|
|
(33 |
) |
Accretion
expense
|
|
|
1,480 |
|
|
|
788 |
|
ARO
as of the end of the period
|
|
$ |
22,670 |
|
|
$ |
10,689 |
|
Of the
total ARO, approximately $4.6 million and $0.4 million is included in accrued
liabilities on the Consolidated Balance Sheet at December 31, 2007 and 2006,
respectively.
Long-term
debt consists of the following:
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Senior
secured revolving line of credit
|
|
$ |
170,000 |
|
|
$ |
165,000 |
|
Second
lien term loan
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
|
245,000 |
|
|
|
240,000 |
|
Less:
current portion of long-term debt
|
|
|
- |
|
|
|
- |
|
|
|
$ |
245,000 |
|
|
$ |
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. In addition,
in 2007, we increased our net borrowings against the Revolver by $5.0 million,
bringing the balance to $170.0 million at December 31,
2007. 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. In May 2007, the borrowing base was
adjusted to $350.0 million. Initial amounts outstanding under the
Revolver bore interest, as amended, at specified margins over the London
Interbank Offered Rate (“LIBOR”) of 1.25% to 2.00% (5.82% at December 31,
2007). These rates over LIBOR were adjusted in May 2007 to be 1.00%
to 1.75%. Such margins will fluctuate based on the utilization of the
facility. Borrowings under the Revolver are collateralized by perfected first
priority liens and security interests on substantially all of the Company’s
assets, including a mortgage lien on oil and natural gas properties having at
least 80% of the pretax SEC PV-10 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, 2007. As of December 31, 2007, the
Company had $179.0 million available for borrowing under their revolving line of
credit. All amounts drawn under the Revolver are due and payable on July 7,
2009.
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% (8.82 %
at December 31, 2007). 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, 2007. The
principal balance of the Term Loan is due and payable on July 7,
2010.
Our
ability to raise capital depends on the current state of the financial markets,
which are subject to general and economic and industry
conditions. Therefore, the availability of and price of capital in
the financial markets could negatively affect our liquidity position. Our
current liquidity is supported by our revolving credit facility maturing on July
7, 2009.
Aggregate
maturities required on long-term debt at December 31, 2007 due in future
years are as follows (In thousands):
2007
|
|
$ |
- |
|
2008
|
|
|
- |
|
2009
|
|
|
170,000 |
|
2010
|
|
|
75,000 |
|
2011
|
|
|
- |
|
Thereafter
|
|
|
- |
|
Total
|
|
$ |
245,000 |
|
(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
On
December 20, 2005, Calpine and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”). On December 19, 2007, the Bankruptcy Court approved
Calpine’s plan of reorganization (“Plan of Reorganization”). On
January 31, 2008, Calpine and certain of its subsidiaries emerged from
bankruptcy.
Calpine’s
Lawsuit Against Rosetta
On June
29, 2007, Calpine commenced an adversary proceeding against the Company in the
Bankruptcy Court (the “Lawsuit”). The complaint alleges that the purchase by the
Company of the domestic oil and natural gas business owned by Calpine (the
“Assets”) in July 2005 for $1.05 billion, prior to Calpine filing for
bankruptcy, was completed when Calpine was insolvent and was for less than a
reasonably equivalent value. Through the Lawsuit, Calpine is seeking (i)
monetary damages for the alleged shortfall in value it received for these Assets
which it estimates to be approximately $400 million, plus interest, or (ii) in
the alternative, return of the Assets from the Company. The Company believes
that the allegations in the Lawsuit are wholly baseless, and the Company
continues to believe that it is unlikely that this challenge by Calpine to the
fairness of the Acquisition will be successful upon the ultimate disposition of
the Lawsuit or, if necessary, in the appellate courts. The Official Committee of
Equity Security Holders and the Official Committee of the Unsecured Creditors
both intervened in the Lawsuit for the stated purpose of monitoring the
proceedings because the committees claimed to have an interest in the Lawsuit,
which the Company disputes because we believe creditors may be paid in full
under Calpine’s Plan of Reorganization without regard to the Lawsuit and equity
holders have no interest in fraudulent conveyance actions. Under
Calpine’s Plan of Reorganization approved by the Bankruptcy Court on December
19, 2007, the Official Committee of Equity Security Holders was dissolved as of
the January 31, 2008 effective date and no longer has any interest in the
Lawsuit. While the Unsecured Creditors Committee also was officially
dissolved as of the same effective date, there are provisions under the approved
Plan of Reorganization that will allow it to remain involved in lawsuits to
which it is a party, which may include this Lawsuit
On
September 10, 2007, the Company filed a motion to dismiss the Lawsuit or, in the
alternative, to stay the Lawsuit. The Bankruptcy Court conducted a hearing upon
the Company’s motion on October 24, 2007. Following the hearing, the Bankruptcy
Court denied the Company’s motion on the basis that certain issues raised by the
Company’s motion were premature as the bankruptcy process had not yet
established how much Calpine’s creditors would receive. On November
5, 2007, the Company filed their answer, affirmative defenses and counterclaims
with respect to the Lawsuit, denying the allegations set forth in both counts of
the Lawsuit, and asserting affirmative defenses to Calpine’s claims as well as
affirmative counterclaims against Calpine related to the Acquisition for (i)
breach of covenant of solvency, (ii) fraud and fraud in a real estate
transaction, (iii) breach of contract, (iv) conversion, (v) civil theft and (vi)
setoff. The parties are currently in agreement that discovery may
continue in the Lawsuit until April 2008. The Bankruptcy Court has
not set a trial date.
Remaining
Issues with Respect to the Acquisition
Separate
from the Calpine lawsuit, Calpine has taken the position that 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”) are “executory
contracts”, which Calpine may assume or reject. Following the July 7,
2005 closing of the Acquisition and as of the date of Calpine’s bankruptcy
filing, there were open issues regarding legal title to certain properties
included in the Purchase Agreement. On September 25, 2007, the Bankruptcy Court
approved Calpine’s Disclosure Statement accompanying its proposed Plan of
Reorganization under Chapter 11 of the Bankruptcy Code, in which Calpine
revealed it had not yet made a decision as to whether to assume or reject its
remaining duties and obligations under the Purchase Agreement. The
Company may contend that the Purchase Agreement is not an executory contract
which Calpine may choose to reject. If the Court were to determine
that the Purchase Agreement is an executory contract, the Company may contend
the various agreements entered into as part of the transaction constitute a
single contract for purposes of assumption or rejection under the Bankruptcy
Code, and the Company may argue that Calpine cannot choose to assume certain of
the agreements and to reject others. This issue may be contested by
Calpine. If the Purchase Agreement is held to be executory, the
deadline by when Calpine must exercise its decision to assume or reject the
Purchase Agreement and the further duties and obligations required therein would
normally have been the date on which Calpine’s Plan of Reorganization was
confirmed; however, in order to address certain issues, Calpine and the Company
have agreed to extend this deadline until fifteen days following the entry of a
final, unappealable order in the Lawsuit, and the parties set forth this
agreement in the Plan of Reorganization approved by the Bankruptcy Court on
December 19, 2007.
Open
Issues Regarding Legal Title to Certain Properties
Under the
Purchase Agreement, Calpine is required to resolve the open issues regarding
legal title to interests in certain properties. At the closing of the
Acquisition on July 7, 2005, the Company retained approximately $75 million
of the purchase price in respect to leases and wells identified by Calpine as
requiring third-party consents or waivers of preferential rights to purchase
that were not received by the parties before closing (“Non-Consent
Properties”). The interests in Non-Consent Properties were not
included in the conveyances delivered at the closing. Subsequent
analysis determined that a significant portion of the Non-Consent Properties did
not require consents or waivers. For that portion of the Non-Consent
Properties for which third-party consents were in fact required and for which
either the Company or Calpine obtained the required consents or waivers, as well
as for all Non-Consent Properties that did not require consents or waivers, the
Company contends Calpine was and is obligated to have transferred to the Company
the record title, free of any mortgages and other liens.
The
approximate allocated value under the Purchase Agreement for the portion of the
Non-Consent Properties subject to a third-party’s preferential right to purchase
is $7.4 million. The Company has retained $7.1 million of the
purchase price under the Purchase Agreement for the Non-Consent Properties
subject to the third-party preferential right, and, in addition, a post-closing
adjustment is required to credit the Company for approximately $0.3 million for
a property which was transferred to it but, if necessary, will be transferred to
the appropriate third party under its exercised preferential purchase right upon
Calpine’s performance of its obligations under the Purchase
Agreement.
The
Company believes all conditions precedent for its receipt of record title, free
of any mortgages or other liens, for substantially all of the Non-Consent
Properties (excluding that portion of these properties subject to the
third-party preferential right) were satisfied earlier, and certainly no later,
than December 15, 2005, when the Company tendered the amounts necessary to
conclude the settlement of the Non-Consent Properties.
The
Company believes it is the equitable owner of each of the Non-Consent Properties
for which Calpine was and is obligated to have transferred the record title and
that such properties are not part of Calpine’s bankruptcy
estate. Upon the Company’s receipt from Calpine of record title, free
of any mortgages or other liens, to these Non-Consent Properties (excluding that
portion of these properties subject to a validly exercised third party’s
preferential right to purchase) and further assurances required to eliminate any
open issues on title to the remaining properties discussed below, the
Company had been prepared to conclude the remaining aspects of the
Acquisition. The Company has excluded from their statement of
operations for the years ended December 31, 2007 and 2006 and six
months ended December 31, 2005, estimated net revenues and estimated production
from interests in certain leases and wells being a portion of the Non-Consent
Properties, including those properties subject to preferential
rights.
On
September 11, 2007, the Bankruptcy Court entered an order approving that certain
Partial Transfer and Release Agreement (“PTRA”) negotiated by and between the
Company and Calpine which, among other things, resolves issues in regard to
title of certain of the other oil and natural gas properties the Company
purchased from Calpine in the Acquisition and for which payment was made to
Calpine on July 7, 2005, and we entered into a new Marketing and Services
Agreement (“MSA”) with Calpine Producer Services, L.P. (“CPS”) for a two-year
period commencing on July 1, 2007 but which is subject to earlier termination by
us on the occurrence of certain events. The additional documentation received
from Calpine under the PTRA eliminates open issues in the Company’s title and
resolves any issues as to the clarity of the Company’s ownership in certain
properties located in the Gulf of Mexico, California, and Wyoming (the “PTRA
Properties”), including all oil and gas properties requiring ministerial
approvals, such as leases with the U.S. Minerals Management Service (“MMS”),
California State Lands Commission (“CSLC”) and U.S. Bureau of Land Management
(“BLM”). However, the PTRA was executed without prejudice to Calpine’s
fraudulent conveyance action or its right, if any, to reject the Purchase
Agreement, and without prejudice to the Company’s rights and legal arguments in
relation thereto, including the Company’s various counterclaims. The
PTRA did not otherwise address or resolve open issues with respect to the
Non-Consent Properties and certain other properties.
The
Company recorded the conveyances of those PTRA Properties in California not
requiring governmental agency approval. On October 30, 2007, the CSLC
approved the assignment of the State of California leases and rights of way to
the Company from Calpine and resolved open issues under an audit the State of
California had conducted as to these Properties. While the
documentation has been filed with the MMS, the Company is still awaiting the
ministerial approval for the assignment of Calpine’s interests in MMS Federal
Offshore leases for South Pelto 17 and South Timalier 252 to the
Company.
Notwithstanding
the PTRA, as a result of Calpine’s bankruptcy filing, it remains uncertain as to
whether Calpine will respond cooperatively as to the remaining outstanding
issues under the Purchase Agreement. If Calpine does not fulfill its contractual
obligations (as a result of rejection of the Purchase Agreement or otherwise)
and does not complete the documentation necessary to resolve these remaining
issues whether under the Purchase Agreement or the PTRA, the Company will pursue
all available remedies, including but not limited to a declaratory judgment to
enforce the Company’s rights and actions to quiet title. After pursuing these
matters, if the Company experiences a loss of ownership with respect to these
properties without receiving adequate consideration for any resulting loss to
the Company, an outcome the Company’s management considers to be unlikely upon
ultimate disposition, including appeals, if any, then the Company could
experience losses which could have a material adverse effect on the Company’s
financial condition, statement of operations or cash flows.
Sale
of Natural Gas to Calpine
In
addition, the issues involving legal title to certain properties, the Company
executed, as part of the interrelated agreements that constitute the Purchase
Agreement, certain natural gas sales agreements with Calpine Energy Services,
L.P. (“CES”), which also filed for bankruptcy on December 20,
2005. During the period following Calpine’s filing for bankruptcy,
CES has continued to make the required deposits into the Company’s margin
account and to timely pay for natural gas production it purchases from the
Company’s subsidiaries under these various natural gas sales
agreements. Although Calpine has indicated in a supplement to its
recently proposed Plan of Reorganization that it intends to assume the CES
natural gas sales agreements with the Company, the Company disagrees that
Calpine may assume anything less than the entire Purchase Agreement and intends
to oppose any effort by Calpine to do less.
Calpine’s
Marketing of the Company’s Production
As part
of the PTRA, the Company entered into the MSA with CPS, effective July 1, 2007,
which was approved by the Bankruptcy Court on September 11, 2007. Under the MSA,
CPS provides marketing and related services in relation to the sales of our
natural gas production and charges the Company a fee. This MSA extends CPS’
obligations to provide such services until June 30, 2009. The MSA is subject to
early termination by the Company upon the occurrence of certain
events.
Events
within Calpine’s Bankruptcy Case
On June
29, 2006, Calpine filed a motion in connection with its pending bankruptcy
proceeding in the Bankruptcy Court seeking the entry of an order authorizing
Calpine to assume certain oil and natural gas leases that Calpine had previously
sold or agreed to sell to the Company in the Acquisition, to the extent those
leases constitute “unexpired leases of non-residential real property” and were
not fully transferred to the Company at the time of Calpine’s filing for
bankruptcy. The oil and gas leases identified in Calpine’s motion
are, in large part, those properties with open issues in regards to their legal
title in certain oil and natural gas leases which Calpine contends it may
possess some legal interest. According to this motion, Calpine filed
its pending bankruptcy proceeding in order to avoid the automatic forfeiture of
any interest it may have in these leases by operation of a bankruptcy code
deadline. Calpine’s motion did not request that the Bankruptcy Court
determine whether these properties belong to the Company or Calpine, but the
Company understands that Calpine’s motion was meant to allow Calpine to preserve
and avoid forfeiture under the Bankruptcy Code of whatever interest Calpine may
possess, if any, in these oil and natural gas leases. The Company
disputes Calpine’s contention that it may have an interest in any significant
portion of these oil and natural gas leases and intends to take the necessary
steps to protect all of the Company’s rights and interest in and to the
leases. Certain of these properties have been subsequently addressed
under the PTRA discussed above.
On July
7, 2006, the Company filed an objection in response to Calpine’s motion, wherein
the Company asserted that oil and natural gas leases constitute interests in
real property that are not subject to “assumption” under the Bankruptcy Code. In
the objection, the Company also requested that (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 MMS has subsequently recognized the Company as owner and operator of all but
two of these properties, two other leases of offshore properties having expired,
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 could seek
mediation to complete the following:
|
·
|
Calpine’s
conveyance of its retained interests in the Non-Consent Properties to the
Company;
|
|
·
|
Calpine’s
execution of all documents and performance of all tasks required under
“further assurances” provisions of the Purchase Agreement with respect to
certain of the oil and natural gas properties for which the Company has
already paid Calpine; and
|
|
·
|
Resolution
of the final amounts the Company is to pay
Calpine.
|
At a
hearing held on July 12, 2006, the Bankruptcy Court took the following
steps:
|
·
|
In
response to an objection filed by the Department of Justice and asserted
by the CSLC that the Debtors’ Motion to Assume Non-Residential Leases and
Set Cure Amounts (the “Motion”), did not allow adequate time for an
appropriate response, Calpine withdrew from the list of oil and gas leases
that were the subject of the Motion those leases issued by the United
States (and managed by the MMS) (the “MMS Oil and Gas Leases”) and the
State of California (and managed by the CSLC) (the “CSLC Leases”).
Calpine, the Department of Justice and the State of California agreed to
an extension of the existing deadline to November 15, 2006 to assume or
reject the MMS Oil and Gas Leases and CSLC Leases under Section 365 of the
Bankruptcy Code, to the extent the MMS Oil and Gas Leases and CSLC Leases
are leases subject to Section 365. The effect of these actions was to
render the objection of the Company inapplicable at that time;
and
|
|
·
|
The
Bankruptcy Court also encouraged Calpine and the Company to arrive at a
business solution to all remaining issues including approximately $68
million payable to Calpine for conveyance of the Non-Consent Properties
(excluding the properties subject to third party’s preferential
right)..
|
On August
1, 2006, the Company filed a number of proofs of claim in the Calpine bankruptcy
asserting claims against a variety of Calpine debtors seeking recovery of $27.9
million in liquidated amounts, as well as unliquidated damages in amounts that
have not presently been determined. In the event that Calpine elects
to reject the Purchase Agreement or otherwise refuses to perform its remaining
obligations therein, the Company anticipates it will be allowed to amend its
proofs of claim to assert any additional damages it suffers as a result of the
ultimate impact of Calpine’s refusal or failure to perform under the Purchase
Agreement. In the bankruptcy, Calpine may elect to contest or dispute
the amount of damages the Company seeks in its proofs of claim. The
Company will assert all rights to offset any of its damages against any funds it
possess that may be owed to Calpine. Until the allowed amount of the
Company’s claims are finally established and the Bankruptcy Court issues its
rulings with respect to Calpine’s approved Plan of Reorganization, the Company
cannot predict what amounts it may recover from the Calpine bankruptcy should
Calpine reject or refuse to perform under the Purchase Agreement.
With
respect to the stipulations between Calpine and MMS and Calpine and CSLC
extending the deadline to assume or reject the MMS Oil and Gas Leases and the
CSLC Leases respectively, these parties further extended this deadline by
stipulation. The deadline was first extended to January 31, 2007, was further
extended to April 15, 2007 with respect to the MMS Oil and Gas Leases and April
30, 2007 with respect to the CSLC Leases, was further extended again to
September 15, 2007 with respect to the MMS Oil and Gas Leases and July 15, 2007
and more recently, October 31, 2007 with respect to the CSLC Leases. The
Bankruptcy Court entered Orders related to the MMS Oil and Gas Leases and CSLC
Leases which included appropriate language that the Company negotiated with
Calpine for the Company’s protection in this regard. The MMS Oil and Gas Leases
and CSLC Leases were included in the PTRA that was approved by the Bankruptcy
Court on September 11, 2007, with the result that there is no further need for
the parties to contest whether the MMS Oil and Gas Leases and the CLSC Leases
are appropriate for inclusion in Calpine’s 365
motion. The PTRA approved by the Bankruptcy Court, among
other things, resolves open issues in regard to the Company’s title to ownership
of all of the unexpired MMS Oil and Gas Leases and the CLSC
Leases. However, the PTRA was executed without prejudice to Calpine’s
fraudulent conveyance action or its rights, if any, to reject the Purchase
Agreement and the Company’s rights and legal arguments in relation
thereto.
On June
20, 2007, Calpine filed its proposed Plan of Reorganization and Disclosure
Statement with the Bankruptcy Court. Calpine had indicated in its
filing with the Court that it believed substantial payments in the form of cash
or newly issued stock, or some combination thereof, would be made to unsecured
creditors under its proposed Plan of Reorganization that could conceivably
result in payment of 100% of allowed claims and possibly provide some payment to
its equity holders. The amounts any plan ultimately distributes to
its various claimants of the Calpine estate, including unsecured creditors, will
depend on the amount of allowed claims that remain following the objection
process. The Bankruptcy Court approved Calpine’s Plan of Reorganization on
December 19, 2007, overruling the Company’s objection to the releases granted by
this Plan to prior and current directors and officers of Calpine and certain of
its law firms and other professional advisors.
On August
3, 2007, the Company and Calpine executed the PTRA, resolving certain open
issues without prejudice to Calpine’s avoidance action and, if the Court
concludes the Purchase Agreement is executory, Calpine’s ability to assume or
reject the Purchase Agreement. The principle terms are as follows:
|
·
|
The
Company extended certain marketing services by executing a new MSA with
CPS through and until June 30, 2009, effective as of July 1,
2007. This agreement is subject to earlier termination rights
by the Company upon the occurrence of certain
events;
|
|
·
|
Calpine
delivers to the Company documents that resolve title issues pertaining to
the Properties, defined as certain previously purchased oil and gas
properties located in the Gulf of Mexico, California and
Wyoming;
|
|
·
|
The
Company assumes all Calpine's rights and obligations for an audit by the
California State Lands Commission on part of the Properties;
and
|
|
·
|
The
Company assumes all rights and obligations for the Properties, including
all plugging and abandonment
liabilities.
|
On
September 11, 2007, the Bankruptcy Court approved the PTRA. The PTRA did not
resolve the open issues on the Non-Consent Properties and certain other
properties.
As a
result of Calpine’s bankruptcy, there remains the possibility that there will be
issues between the Company and Calpine that could amount to material
contingencies in relation to the litigation filed by Calpine against the Company
or the Purchase Agreement, including unasserted claims and assessments with
respect to (i) 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 PTRA; and (iii) the issues pertaining to the
Non-Consent Properties.
Arbitration
between Calpine Corp./Rosetta and Pogo Producing Company
On
September 1, 2004, Calpine and Calpine Natural Gas L.P. sold their New Mexico
oil and natural gas assets to Pogo Producing Company (“Pogo”). During the course
of that sale, Pogo made three title defect claims on properties sold by Calpine
(valued at approximately $2.7 million in the aggregate, subject to a $0.5
million deductible assuming no reconveyance) claiming that certain leases
subject to the sale had expired because of lack of production. With Rosetta’s
assistance, Calpine had undertaken without success to resolve this matter by
obtaining ratifications of a majority of the questionable leases. Calpine filed
for bankruptcy protection before Pogo filed arbitration against it. Even though
this is a retained liability of Calpine, Calpine had earlier declined to accept
the Company’s tender of defense and indemnity when Pogo filed for arbitration
against the Company. The Company filed a motion to stay this
arbitration under the automatic stay provision of the Bankruptcy Code which
motion was granted by the Bankruptcy Court on April 24, 2007. We intend to
cooperate with Calpine in defending against Pogo’s claim should it resume;
however, it is too early for management to determine whether this matter will
affect the Company, and if so, in what amount. This is due, but not
limited to uncertainty concerning (1) whether or not Pogo’s proofs of claim will
be fully satisfied by Calpine under its approved Plan of Reorganization; and (2)
whether, and if so, the extent to which, Calpine may reimburse the Company for
its claim for its defense costs and any arbitration award regarding the Pogo
claim.
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 $2.6 million, $2.4 million and $
0.6 million for the years ended December 31, 2007 and 2006 and for six
months ended December 31, 2005, respectively. For the six months ended
June 30, 2005 (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 for the six months ended June 30, 2005
(predecessor).
Future
minimum annual rental commitments under non-cancelable leases at
December 31, 2007 are as follows (In thousands):
2008
|
|
2,365
|
|
2009
|
|
2,771
|
|
2010
|
|
2,684
|
|
2011
|
|
2,753
|
|
2012
|
|
2,782
|
|
Thereafter
|
|
|
3,063 |
|
|
|
$ |
16,418 |
|
The
Company has drilling rig commitments of $4.1 million for 2008.
(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 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 Rosetta’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, Rosetta 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
years ended December 31, 2007 and 2006 was $6.8 million and $5.7 million,
respectively, with an associated tax benefit of $2.5 million and $2.1
million, respectively. 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)
stock-based compensation expense was $0.2 million with a tax benefit of
$0.1million. The remaining unrecognized compensation expense associated with
total unvested awards as of December 31, 2007 was $9.8 million.
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 majority of options generally vest over a three year
period.
The
weighted average fair value at date of grant for options granted during the
years ended December 31, 2007 and 2006 and the six months ended December 31,
2005 was $ 9.51 per share, $ 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:
|
|
Year
Ended
December 31,
2007
|
|
|
Year
Ended
December 31,
2006
|
|
|
Six
Months Ended
December 31,
2005
|
|
Expected
option term (years)
|
|
|
6.5 |
|
|
|
6.5 |
|
|
|
6.5 |
|
Expected
volatility
|
|
|
42.45 |
% |
|
|
56.65 |
% |
|
|
54.62 |
% |
Expected
dividend rate
|
|
|
0.00 |
% |
|
|
0.00 |
% |
|
|
0.00 |
% |
Risk
free interest rate
|
|
|
4.36%
- 5.00 |
% |
|
|
4.33%
- 5.15 |
% |
|
|
4.03%
- 4.60 |
% |
The
Company has assumed an annual forfeiture rate of 5% for the options granted in
2007 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, 2007:
|
|
Shares
|
|
|
Weighted
Average Exercise Price
Per
Share
|
|
|
Weighted
Average Remaining Contractual Term
(In
years)
|
|
|
Aggregate
Intrinsic Value
(In
thousands)
|
|
Outstanding
at December 31, 2006
|
|
|
853,354 |
|
|
$ |
16.80 |
|
|
|
|
|
|
|
Granted
|
|
|
316,100 |
|
|
|
19.11 |
|
|
|
|
|
|
|
Exercised
|
|
|
(40,104 |
) |
|
|
16.26 |
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(156,750 |
) |
|
|
17.60 |
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2007
|
|
|
972,600 |
|
|
$ |
17.45 |
|
|
|
8.22 |
|
|
$ |
2,293 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
Vested and Exercisable at December 31, 2007
|
|
|
618,124 |
|
|
$ |
17.25 |
|
|
|
8.13 |
|
|
$ |
1,616 |
|
Stock-based
compensation expense recorded for stock option awards for the years ended
December 31, 2007 and 2006 was $3.9 million and $2.9 million,
respectively. 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, 2007 for all
outstanding stock options is $3.3 million and will be recognized over a weighted
average period of 1.05 years.
The total
intrinsic value of options exercised during the years ended December 31, 2007
and 2006 is $0.2 million and $0.1 million, respectively. 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. The majority of restricted stock vests over a three year
period. 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 related to restricted stock held by the
Company’s employees at December 31, 2007:
|
|
Shares
|
|
|
Weighted
Average Grant Date Fair Value
|
|
Non-vested
shares outstanding at December 31, 2006
|
|
|
326,900 |
|
|
$ |
17.05 |
|
Granted
|
|
|
315,350 |
|
|
|
19.48 |
|
Vested
|
|
|
(96,750 |
) |
|
|
16.95 |
|
Forfeited
|
|
|
(90,075 |
) |
|
|
18.34 |
|
Non-vested
shares outstanding at December 31, 2007
|
|
|
455,425 |
|
|
$ |
18.50 |
|
The
non-vested restricted stock outstanding at December 31, 2007 generally 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 fair value of
awards vested for the year ended December 31, 2007 was $2.0
million.
Stock-based
compensation expense recorded for restricted stock awards for the years ended
December 31, 2007 and 2006 and the six months ended December 31, 2005 was $2.9
million, $2.8 million and $4.2 million, respectively. Unrecognized
expense as of December 31, 2007 for all outstanding restricted stock awards is
$6.5 million and will be recognized over a weighted average period of 1.41
years.
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, 2007, the Company had a deferred tax asset related to federal
and state net operating loss carryforwards of approximately $33.1
million. Approximately $6.0 million of the net operating loss
carryforward will expire in 2025. The remaining amount will begin to
expire 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 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 against future
taxable income recorded on deferred tax assets as the Company believes it is
more likely than not that the asset will be utilized.
The
Company’s income tax expense (benefit) consists of the following:
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year
Ended December 31, 2007
|
|
|
Year
Ended December 31, 2006
|
|
|
Six
Months Ended December 31, 2005
|
|
|
Six
Months Ended June 30, 2005
|
|
|
|
(In
thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
7,556 |
|
State
|
|
|
115 |
|
|
|
172 |
|
|
|
- |
|
|
|
1,067 |
|
|
|
|
115 |
|
|
|
172 |
|
|
|
- |
|
|
|
8,623 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
31,979 |
|
|
|
24,132 |
|
|
|
10,139 |
|
|
|
2,519 |
|
State
|
|
|
1,938 |
|
|
|
3,340 |
|
|
|
1,398 |
|
|
|
354 |
|
|
|
|
33,917 |
|
|
|
27,472 |
|
|
|
11,537 |
|
|
|
2,873 |
|
Total
income tax expense (benefit)
|
|
$ |
34,032 |
|
|
$ |
27,644 |
|
|
$ |
11,537 |
|
|
$ |
11,496 |
|
The
differences between income taxes computed using the statutory federal income tax
rate and that shown in the statement of operations are summarized as
follows:
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year
Ended December 31, 2007
|
|
|
Year
Ended December 31, 2006
|
|
|
Six
Months Ended December 31, 2005
|
|
|
Six
Months Ended June 30, 2005
|
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
US
Statutory Rate
|
|
$ |
31,933 |
|
|
|
35.0 |
% |
|
$ |
25,288 |
|
|
|
35.0 |
% |
|
$ |
10,175 |
|
|
|
35.0 |
% |
|
$ |
10,562 |
|
|
|
35.0 |
% |
Income/franschise
tax, net of federal benefit
|
|
|
2,053 |
|
|
|
2.3 |
% |
|
|
2,283 |
|
|
|
3.2 |
% |
|
|
909 |
|
|
|
3.1 |
% |
|
|
924 |
|
|
|
3.1 |
% |
Transaction
costs not deductible
|
|
|
- |
|
|
|
0.0 |
% |
|
|
- |
|
|
|
0.0 |
% |
|
|
466 |
|
|
|
1.6 |
% |
|
|
- |
|
|
|
0.0 |
% |
Permanent
differences and other
|
|
|
46 |
|
|
|
0.0 |
% |
|
|
73 |
|
|
|
0.0 |
% |
|
|
(13 |
) |
|
|
0.0 |
% |
|
|
10 |
|
|
|
0.0 |
% |
Total
tax expense (Benefit)
|
|
$ |
34,032 |
|
|
|
37.3 |
% |
|
$ |
27,644 |
|
|
|
38.2 |
% |
|
$ |
11,537 |
|
|
|
39.7 |
% |
|
$ |
11,496 |
|
|
|
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. Future effective tax
rates could be adversely affected 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,
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Deferred
tax assets
|
|
|
|
|
|
|
Accrued
liabilities not currently deductible
|
|
$ |
3,273 |
|
|
$ |
1,410 |
|
Hedge
activity
|
|
|
4,289 |
|
|
|
- |
|
Net
operating loss carryforward
|
|
|
12,506 |
|
|
|
30,428 |
|
Other
|
|
|
892 |
|
|
|
413 |
|
Total
deferred tax assets
|
|
|
20,960 |
|
|
|
32,251 |
|
Oil
and gas basis differences
|
|
|
(89,397 |
) |
|
|
(71,142 |
) |
Hedge
activity
|
|
|
- |
|
|
|
(3,821 |
) |
Other
|
|
|
(200 |
) |
|
|
(120 |
) |
Total
gross deferred tax liabilities
|
|
|
(89,597 |
) |
|
|
(75,083 |
) |
Net
deferred tax assets (liabilities)
|
|
$ |
(68,637 |
) |
|
$ |
(42,832 |
) |
Accounting for Uncertainty in Income
Taxes. In June 2006, the FASB issued FIN 48. FIN 48 requires
that we recognize the financial statement benefit of a tax position only after
determining that the relevant tax authority would more likely than not sustain
the position following an audit. For a tax position meeting the more likely than
not threshold, the amount recognized in the financial statements is the largest
benefit that has a greater than 50% likelihood of being realized upon ultimate
settlement with the relevant tax authority. As a result of the
implementation of FIN 48, the Company did not have any unrecognized tax benefits
and there was no effect on our financial condition or results of operations as a
result of implementing FIN 48.
It is
expected that the amount of unrecognized tax benefits may change in the next
twelve months; however, the Company does not expect the change to have a
significant impact on our financial condition or results of
operations. As of December 31, 2007, the Company has no unrecognized
tax benefits that if recognized would affect the effective tax
rate.
The
Company files income tax returns in the U.S. and in various state
jurisdictions. With few exceptions, the Company is subject to US
federal, state and local income tax examinations by tax authorities for tax
periods 2005 and forward.
Estimated
interest and penalties related to potential underpayment on any unrecognized tax
benefits are classified as a component of tax expense in the consolidated
statement of operations. The Company has not recorded any interest or
penalties associated with unrecognized tax benefits.
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 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,
2007
|
|
|
Year
Ended
December 31,
2006
|
|
|
Six
Months Ended
December 31,
2005
|
|
|
Six
Months Ended
June 30,
2005
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,379 |
|
|
|
50,237 |
|
|
|
50,003 |
|
|
|
50,000 |
|
Dilution
effect of stock option and awards at the end of the
period
|
|
|
210 |
|
|
|
171 |
|
|
|
186 |
|
|
|
160 |
|
Diluted
weighted average number of shares outstanding
|
|
|
50,589 |
|
|
|
50,408 |
|
|
|
50,189 |
|
|
|
50,160 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Anti-dilutive
stock awards and shares
|
|
|
385 |
|
|
|
198 |
|
|
|
- |
|
|
|
- |
|
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 Securities and Exchange Commission (“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.
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”. Also, as
all of our operations are located in the U.S., all of our costs are included in
one cost pool. 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,
2007 (1)
|
|
|
Year
Ended
December 31,
2006 (1)
|
|
|
Six
Months Ended
December 31,
2005 (1)
|
|
|
Six
Months Ended
June 30,
2005
|
|
Oil
and Natural Gas Revenue
|
|
(In
thousands)
|
|
California
|
|
$ |
110,607 |
|
|
$ |
76,408 |
|
|
$ |
48,138 |
|
|
$ |
43,385 |
|
Rocky
Mountains
|
|
|
10,676 |
|
|
|
2,115 |
|
|
|
338 |
|
|
|
161 |
|
Mid-Continent
|
|
|
2,287 |
|
|
|
1,879 |
|
|
|
1,309 |
|
|
|
842 |
|
Lobo
|
|
|
117,368 |
|
|
|
71,450 |
|
|
|
39,062 |
|
|
|
26,474 |
|
Perdido
|
|
|
26,518 |
|
|
|
29,538 |
|
|
|
14,675 |
|
|
|
12,380 |
|
State
Waters
|
|
|
8,789 |
|
|
|
8,183 |
|
|
|
6,761 |
|
|
|
2,345 |
|
Other
Onshore
|
|
|
23,618 |
|
|
|
25,878 |
|
|
|
9,364 |
|
|
|
7,662 |
|
Gulf
of Mexico
|
|
|
40,700 |
|
|
|
26,734 |
|
|
|
9,921 |
|
|
|
10,542 |
|
Other
|
|
|
- |
|
|
|
- |
|
|
|
112 |
|
|
|
40 |
|
|
|
$ |
340,563 |
|
|
$ |
242,185 |
|
|
$ |
129,680 |
|
|
$ |
103,831 |
|
|
|
December
31,
|
|
|
|
2007
|
|
|
2006
|
|
Oil
and Natural Gas Properties
|
|
(In
thousands)
|
|
California
|
|
$ |
540,924 |
|
|
$ |
435,167 |
|
Rocky
Mountains
|
|
|
76,343 |
|
|
|
44,455 |
|
Mid-Continent
|
|
|
14,698 |
|
|
|
9,584 |
|
Lobo
|
|
|
515,096 |
|
|
|
426,348 |
|
Perdido
|
|
|
76,259 |
|
|
|
52,702 |
|
State
Waters
|
|
|
55,918 |
|
|
|
26,922 |
|
Other
Onshore
|
|
|
130,977 |
|
|
|
102,734 |
|
Gulf
of Mexico
|
|
|
155,867 |
|
|
|
125,425 |
|
Other
|
|
|
6,393 |
|
|
|
4,562 |
|
|
|
$ |
1,572,475 |
|
|
$ |
1,227,899 |
|
___________________________________
|
(1)
|
Excludes
the effects of hedging gains of $22.9 million and $29.6 million for the
years ended December 31, 2007 and 2006, respectively, and hedging losses
of $16.6 million for the six months ended December 31,
2005. There was no hedging activity for the six months ended
June 30, 2005.
|
Major
Customers
For the
year ended December 31, 2007, the Company had one major customer, Calpine Energy
Services (“CES”), a Calpine affiliate, which accounted for approximately 55% of
the Company’s consolidated annual revenue. The Company’s annual
consolidated revenue from CES accounted for approximately 45% for the year ended
December 31, 2006 and 80% for the six months ended December 31, 2005,
respectively, and is reflected in oil and natural gas sales.
For the
years ended December 31, 2007 and 2006 and the six months ended
December 31, 2005, revenues from sales to CES were
$201.4 million, $99.1 million and $75.0 million,
respectively. There was no receivable from CES at December 31,
2007 or 2006. For the six months ended June 30, 2005,
revenues from sales to CES were $82.0 million. 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, 2007 and 2006, the Company had
$20.4 million and $17.9 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 new MSA with Calpine Producer Services (“CPS”) in
connection with the PTRA settlement on August 3, 2007 for the period July 1,
2007 through June 30, 2009, subject to earlier termination on the
occurrence of certain events. The MSA covers a majority of 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 0.50%. For the years ended December 31, 2007 and 2006 and the six months
ended December 31, 2005, the fee was approximately $2.5 million,
$2.3 million and $1.4 million, 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)
|
Related
Party Transactions
|
Successor
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. LOTO II is indirectly owned in part by family trusts established by
our director G. Louis Graziadio, III. 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.
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.
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,
2007, 2006, and 2005, 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 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.
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, 2007 and
2006:
|
|
Successor
|
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,499,046 |
|
|
$ |
1,167,588 |
|
Unproved
properties
|
|
|
40,903 |
|
|
|
37,813 |
|
Total
|
|
|
1,539,949 |
|
|
|
1,205,401 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(291,321 |
) |
|
|
(143,216 |
) |
Net
capitalized costs
|
|
$ |
1,248,628 |
|
|
$ |
1,062,185 |
|
Company's
share of equity method investees' net capitalized costs
|
|
$ |
1,198 |
|
|
$ |
1,166 |
|
Pursuant
to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net
capitalized cost includes asset retirement cost of $20.1 million and $9.6
million as of December 31, 2007 and 2006, 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 years ended December 31, 2007 and 2006
(Successor), six months ended December 31, 2005 (Successor) and
June 30, 2005 (Predecessor):
|
|
(In
thousands)
|
|
Year
Ended December 31, 2007 (Successor)
|
|
|
|
Acquisition
costs of properties
|
|
|
|
Proved
|
|
$ |
40,760 |
|
Unproved
|
|
|
23,824 |
|
Subtotal
|
|
|
64,584 |
|
Exploration
costs
|
|
|
90,117 |
|
Development
costs
|
|
|
178,894 |
|
Total
|
|
$ |
333,595 |
|
Company's
share of equity method investees' costs of property acquisition,
exploration and development
|
|
$ |
101 |
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
(In
thousands)
|
|
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 |
|
|
|
|
|
|
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 |
|
Results
of operations for oil and natural gas producing activities
|
|
Successor
|
|
|
Predecessor
|
|
|
|
Year
Ended
December 31,
2007
|
|
|
Year
Ended
December 31,
2006
|
|
|
Six
Months Ended
December 31,
2005
|
|
|
Six
Months Ended
June 30,
2005
|
|
Oil
and natural gas producing revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
Third-party
|
|
$ |
363,468 |
|
|
$ |
271,751 |
|
|
$ |
113,090 |
|
|
$ |
21,803 |
|
Affiliate
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
81,952 |
|
Total
Revenues
|
|
|
363,468 |
|
|
|
271,751 |
|
|
|
113,090 |
|
|
|
103,755 |
|
Exploration
expenses, including dry hole
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
4,317 |
|
Production
costs
|
|
|
60,140 |
|
|
|
47,507 |
|
|
|
22,314 |
|
|
|
22,295 |
|
Depreciation,
depletion, and amortization
|
|
|
152,882 |
|
|
|
105,886 |
|
|
|
40,500 |
|
|
|
30,679 |
|
Income
before income taxes
|
|
|
150,446 |
|
|
|
118,358 |
|
|
|
50,276 |
|
|
|
46,464 |
|
Income
tax provision
|
|
|
56,041 |
|
|
|
44,621 |
|
|
|
19,155 |
|
|
|
17,656 |
|
Results
of operations
|
|
$ |
94,405 |
|
|
$ |
73,737 |
|
|
$ |
31,121 |
|
|
$ |
28,808 |
|
Company's
share of equity method investees' results of operations for producing
activities
|
|
$ |
415 |
|
|
$ |
227 |
|
|
$ |
241 |
|
|
$ |
161 |
|
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, 2007, 2006, and
2005, 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 years ended December 31, 2007 and 2006 and six months ended December
31, 2005, and the item titled “Other” relates to estimated reserves for
interests in certain leases and wells associated with the Non-Consent
Properties.
Natural
gas (Bcf)(1):
|
|
|
|
Net
proved reserves at January 1, 2005 (Predecessor)
|
|
|
374 |
|
Revisions
of previous estimates
|
|
|
(11 |
) |
Purchases
in place
|
|
|
- |
|
Extensions,
discoveries and other additions
|
|
|
28 |
|
Sales
in place
|
|
|
- |
|
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) (6)
|
|
|
390 |
|
Revisions
of previous estimates
|
|
|
(30 |
) |
Purchases
in place
|
|
|
10 |
|
Extensions,
discoveries and other additions
|
|
|
72 |
|
Sales
in place
|
|
|
- |
|
Production
|
|
|
(42 |
) |
Net
proved reserves at December 31, 2007 (Successor) (6)
|
|
|
400 |
|
Company's
proportional interst in reserves of investees' accounted for by the equity
method - December 31, 2007 (Successor)
|
|
|
5 |
|
Natural
gas liquids and crude oil (MBbl)(2)(3)
|
|
|
|
Net
proved reserves at January 1, 2005 (Predecessor)
|
|
|
2,611 |
|
Revisions
of previous estimates
|
|
|
153 |
|
Purchases
in place
|
|
|
108 |
|
Extensions,
discoveries and other additions
|
|
|
(9 |
) |
Sales
in place
|
|
|
- |
|
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) (6)
|
|
|
2,930 |
|
Revisions
of previous estimates
|
|
|
- |
|
Purchases
in place
|
|
|
- |
|
Extensions,
discoveries and other additions
|
|
|
652 |
|
Sales
in place
|
|
|
- |
|
Production
|
|
|
(561 |
) |
Net
proved reserves at December 31, 2007 (Successor) (6)
|
|
|
3,021 |
|
Company's
proportional interst in reserves of investees' accounted for by the equity
method - December 31, 2007 (Successor)
|
|
|
- |
|
Bcfe
(1) equivalents (4)
|
|
|
|
Net
proved reserves at January 1, 2005 (Predecessor)
|
|
|
389 |
|
Revisions
of previous estimates
|
|
|
(10 |
) |
Purchases
in place
|
|
|
- |
|
Extensions,
discoveries and other additions
|
|
|
29 |
|
Sales
in place
|
|
|
- |
|
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) (6)
|
|
|
408 |
|
Revisions
of previous estimates
|
|
|
(30 |
) |
Purchases
in place
|
|
|
10 |
|
Extensions,
discoveries and other additions
|
|
|
76 |
|
Sales
in place
|
|
|
- |
|
Production
|
|
|
(46 |
) |
Net
proved reserves at December 31, 2007 (Successor) (6)
|
|
|
418 |
|
Company's
proportional interst in reserves of investees' accounted for by the equity
method - December 31, 2007 (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, 2005 (6)
|
|
|
223 |
|
|
|
1,320 |
|
|
|
231 |
|
December
31, 2006 (6)
|
|
|
251 |
|
|
|
1,965 |
|
|
|
263 |
|
December
31, 2007 (6)
|
|
|
286 |
|
|
|
2,658 |
|
|
|
302 |
|
___________________________________
|
(1)
|
Billion
cubic feet or billion cubic feet equivalent, as
applicable
|
|
(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)
|
Estimated
reserves pertaining to interests in certain leases and wells associated
with the Non-Consent Properties.
|
|
(6)
|
Excludes
estimated reserves pertaining to interests in certain leases and wells
associated with the 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, 2007, 2006 and 2005.
|
|
(In
millions)
|
|
December
31, 2007
|
|
|
|
Future
cash inflows
|
|
$ |
3,026 |
|
Future
production costs
|
|
|
(819 |
) |
Future
development costs
|
|
|
(302 |
) |
Future
net cash flows before income taxes
|
|
|
1,905 |
|
Future
income taxes
|
|
|
(323 |
) |
Future
net cash flows
|
|
|
1,582 |
|
Discount
to present value at 10% annual rate
|
|
|
(628 |
) |
Standardized
measure of discounted future net cash flows relating to proved natural
gas, natural gas liquids and crude oil reserves
|
|
$ |
954 |
|
Company's
share of equity method investee's standardized measure of discounted
future net cash flows
|
|
$ |
2 |
|
December
31, 2006
|
|
|
|
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 |
|
|
|
|
|
|
December
31, 2005
|
|
|
|
|
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 |
|
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, 2007, 2006 and 2005.
|
|
(In
millions)
|
|
Balance,
January 1, 2005 (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 |
) |
Purchases
of reserve in place
|
|
|
- |
|
Sales
of reserves in place
|
|
|
- |
|
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 |
|
Sales
and transfers of natural gas, natural gas liquids and crude oil produced,
net of production costs
|
|
|
(303 |
) |
Net
changes in prices and production costs
|
|
|
253 |
|
Extensions,
discoveries, additions and improved recovery, net of related
costs
|
|
|
283 |
|
Development
costs incurred
|
|
|
92 |
|
Revisions
of previous quantity estimates and development costs
|
|
|
(76 |
) |
Accretion
of discount
|
|
|
79 |
|
Net
change in income taxes
|
|
|
(113 |
) |
Purchases
of reserve in place
|
|
|
38 |
|
Sales
of reserves in place
|
|
|
- |
|
Changes
in timing and other
|
|
|
(21 |
) |
Balance
December 31, 2007 (Successor) (1)
|
|
$ |
954 |
|
___________________________________
(1)
|
Excludes
non-consent properties
|
Rosetta
Reserouces Inc.
Selected
Data
Quarterly
Information
(Unaudited)
Summaries
of the Company’s results of operations by quarter for the years ended 2007 and
2006 are as follows:
|
|
2007
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
|
(In
thousands, except per share data)
|
|
Revenues
|
|
$ |
75,796 |
|
|
$ |
86,874 |
|
|
$ |
89,718 |
|
|
$ |
111,101 |
|
Operating
Income
|
|
|
25,969 |
|
|
|
25,317 |
|
|
|
24,415 |
|
|
|
30,898 |
|
Net
Income
|
|
|
13,991 |
|
|
|
13,091 |
|
|
|
12,713 |
|
|
|
17,410 |
|
Basic
earnings per share
|
|
$ |
0.28 |
|
|
$ |
0.26 |
|
|
$ |
0.25 |
|
|
$ |
0.35 |
|
Diluted
earnings per share
|
|
$ |
0.28 |
|
|
$ |
0.26 |
|
|
$ |
0.25 |
|
|
$ |
0.34 |
|
|
|
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 |
|
Item
9. Changes in and Disagreements With Accountants on
Accounting and Financial Disclosure
None
Evaluation
of 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, 2007.
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, 2007, our disclosure controls and procedures
were effective.
Management’s
Report on Internal Control Over Financial Reporting
Management,
including our Chief Executive Officer and Chief Financial Officer, is
responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a –
15(f). Management conducted an assessment as of December 31, 2007 of
the effectiveness of our internal control over financial reporting based on the
framework in Internal Control
– Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (“COSO”). Based on that
evaluation, management concluded that our internal control over financial
reporting was effective as of December 31, 2007, based on criteria in Internal Control – Integrated
Framework issued by the COSO.
The
effectiveness of the Company’s internal control over financial reporting as of
December 31, 2007, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which
is included in Item 8 of this Annual Report on Form 10-K.
Changes
in Internal Control Over Financial Reporting
There has
been no change in our internal control over financial reporting during the
quarter ended December 31, 2007 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
Item
9B. Other Information
In the
fourth quarter of 2007, John M. Thibeaux, Michael H. Hickey and Edward
E. Seeman entered into Amended and Restated Employment Agreements with the
Company so that their employment agreements comply with the new tax provisions
of the Internal Revenue Code Section 409A, which amendments are respectively
attached hereto as Exhibits 10.36, 10.37 and 10.38.
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 2008 annual meeting.
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 2008 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 2008 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 2008 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 2008 annual
meeting.
Part
IV
Item
15. Exhibits and Financial Statement
Schedules
|
1.
|
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 53 of this
report.
|
|
(2)
|
Financial
Statement Schedules:
|
None
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)).
|
|
|
|
10.14
†
|
|
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)).
|
|
|
|
10.28
†
|
|
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)).
|
|
|
|
10.30
†
|
|
Separation
and General Release with B.A. Berilgen (incorporated herein by reference
to Exhibit 10.1 to Current Report on Form 8K filed July 6,
2007).
|
|
|
|
10.31
†
|
|
Employment
Agreement with Randy L. Limbacher (incorporated herein by reference to
Exhibit 10.1 to Current Report on Form 8K filed November 5,
2007).
|
|
|
|
10.32
†
|
|
Second
Amended Employment Agreement with Michael J. Rosinski (incorporated herein
by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed
November 9, 2007).
|
|
|
|
10.33
†
|
|
Amended
Employment Agreement with Charles S. Chambers (incorporated herein by
reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed November
9, 2007).
|
|
|
|
10.34
|
|
Partial
Transfer and Settlement Agreement with Calpine Corporation (incorporated
herein by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q filed
November 9, 2007).
|
|
|
|
10.35
|
|
Marketing
and Related Services Agreement with Calpine Natural Gas Services, L.P.
(incorporated herein by reference to Exhibit 10.5 to Quarterly Report on
Form 10-Q filed November 9, 2007).
|
|
|
|
10.36
†*
|
|
Amended
and Restated Employment Agreement with John M. Thibeaux attached hereto as
Exhibit 10.36.
|
|
|
|
10.37
†*
|
|
Amended and
Restated Employment Agreement with Michael H. Hickey attached
hereto as Exhibit 10.37.
|
|
|
|
10.38
†*
|
|
Amended
and Restated Employment Agreement with Edward E. Seeman attached hereto as
Exhibit 10.38.
|
|
|
|
10.39†
|
|
General
Release Agreement with John M. Thibeaux (incorporated
herein by reference to Exhibit 10.1 to Form 8-K filed on February 22,
2008).
|
|
|
|
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 Chief Executive Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
31.2*
|
|
Certification
of Periodic Financial Reports by Chief Financial Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
32.1*
|
|
Certification
of Periodic Financial Reports by Chief Executive Officer and Chief
Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act
of 2002.
|
____________________________________
†
|
Management
contract or compensatory plan or arrangement required to be filed as an
exhibit hereto.
|
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 February 29, 2008.
|
ROSETTA
RESOURCES INC.
|
|
By:
|
/s/
Randy L. Limbacher
|
|
|
Randy
L. Limbacher, President and
|
|
|
Chief
Executive Officer
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, 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/
Randy L. Limbacher
|
|
President
and Chief Executive Officer
|
|
February
29, 2008
|
Randy
L. Limbacher
|
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
|
/s/
Michael J. Rosinski
|
|
Executive
Vice President and Chief
|
|
February
29, 2008
|
Michael
J. Rosinski
|
|
Financial
Officer (Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/
Denise D. Bednorz
|
|
Vice
President, Controller
|
|
February
29, 2008
|
Denise
D. Bednorz
|
|
(Principal
Accounting Officer)
|
|
|
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|
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/s/
D. Henry Houston
|
|
Non-Executive
Chairman, Director
|
|
February
29, 2008
|
D.
Henry Houston
|
|
|
|
|
|
|
|
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/s/
Richard W. Beckler
|
|
Director
|
|
February
29, 2008
|
Richard
W. Beckler
|
|
|
|
|
|
|
|
|
|
/s/
Donald D. Patteson, Jr.
|
|
Director
|
|
February
29, 2008
|
Donald
D. Patteson, Jr.
|
|
|
|
|
|
|
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|
|
/s/
G. Louis Graziadio, III
|
|
Director
|
|
February
29, 2008
|
G.
Louis Graziadio, III
|
|
|
|
|
|
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|
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|
/s/
Josiah O Low, III
|
|
Director
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|
February
29, 2008
|
Josiah
O Low, III
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|
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.
Exploitation. Optimizing
oil and gas production from producing properties or establishing additional
reserves in producing areas through additional drilling or the application of
new technology.
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.”
Pay. A
reservoir or portion of a reservoir that contains economically producible
hydrocarbons. The overall interval in which pay sections occur is the
gross pay; the smaller portions of the gross pay that meet local criteria for
pay (such as a minimum porosity, permeability and hydrocarbon saturation) are
net pay.
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 producing or is capable of production, including
natural gas wells awaiting pipeline connections to commence deliveries and oil
wells awaiting connection to production facilities.
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)).
|
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)).
|
|
|
|
10.14
†
|
|
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)).
|
|
|
|
10.28
†
|
|
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)).
|
|
|
|
10.30
†
|
|
Separation
and General Release with B.A. Berilgen (incorporated herein by reference
to Exhibit 10.1 to Current Report on Form 8K filed July 6,
2007).
|
|
|
|
10.31
†
|
|
Employment
Agreement with Randy L. Limbacher (incorporated herein by
reference to Exhibit 10.1 to Current Report on Form 8K filed
November 5, 2007).
|
|
|
|
10.32
†
|
|
Second
Amended Employment Agreement with Michael J. Rosinski (incorporated herein
by reference to Exhibit 10.2 to Quarterly Report on Form 10-Q filed
November 9, 2007).
|
|
|
|
10.33
†
|
|
Amended
Employment Agreement with Charles S. Chambers (incorporated herein by
reference to Exhibit 10.3 to Quarterly Report on Form 10-Q filed November
9, 2007).
|
|
|
|
10.34
|
|
Partial
Transfer and Settlement Agreement with Calpine Corporation (incorporated
herein by reference to Exhibit 10.4 to Quarterly Report on Form 10-Q filed
November 9, 2007).
|
|
|
|
10.35
|
|
Marketing
and Related Services Agreement with Calpine Natural Gas Services, L.P.
(incorporated herein by reference to Exhibit 10.5 to form 10K filed
November 9, 2007).
|
|
|
|
|
|
Amended
and Restated Employment Agreement with John M. Thibeaux attached hereto as
Exhibit 10.36.
|
|
|
|
|
|
Amended and
Restated Employment Agreement with Michael H. Hickey attached
hereto as Exhibit 10.37.
|
|
|
|
|
|
Amended
and Restated Employment Agreement with Edward E. Seeman attached hereto as
Exhibit 10.38.
|
|
|
|
10.39
†
|
|
General
Release Agreement with John M. Thibeaux (incorporated herein by reference
to Exhibit 10.1 to Form 8-K filed on February 22,
2008).
|
|
|
|
14.1
|
|
Code
of Ethics posted on the Company’s website at www.rosettaresources.com.
|
|
|
|
|
|
Subsidiaries
of the registrant
|
|
|
|
|
|
Consent
of PricewaterhouseCoopers LLP
|
|
|
|
23.2* |
|
Consent
of PricewaterhouseCoopers LLP |
|
|
|
|
|
Consent
of Netherland, Sewell & Associates, Inc.
|
|
|
|
|
|
Certification
of Periodic Financial Reports by Chief Executive Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
Certification
of Periodic Financial Reports by Chief Financial Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
|
|
|
|
|
|
Certification
of Periodic Financial Reports by Chief Executive Officer and Chief
Financial Officer in satisfaction of Section 906 of the Sarbanes-Oxley Act
of 2002.
|
___________________________________
†
|
Management
contract or compensatory plan or arrangement required to be filed as an
exhibit hereto.
|
102