form10k.htm
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
T
|
Annual
Report Pursuant To Section 13 or 15(d) of The Securities Exchange Act of
1934
|
For
The Fiscal Year Ended December 31, 2008
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)
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 Securities Act.
Yes £ No S
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or 15(d) of the Act.
Yes S No £
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. £
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 a smaller reporting company)
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Indicate
by check mark whether the registrant is a shell company (as defined in 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 30, 2008 was approximately $1.5
billion based on the closing price of $28.50 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 20, 2009 was 52,131,612.
Documents
Incorporated By Reference
Information
required by Part III will either be included in Rosetta Resources Inc.’s
definitive proxy statement relating to its 2009 annual meeting of stockholders
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 REGARDING FORWARD-LOOKING STATEMENTS
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, affects 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 of this Form 10-K. 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 77.
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 core areas of the
Sacramento Basin of California, the Rockies, and South Texas. In
addition, we have non-core positions in 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” or
“Rosetta”) 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. 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. We operate in one business segment. See
Item 8. Financial Statements and Supplementary Data, Note 15 - Operating
Segments.
Pursuant
to the Acquisition, we entered into several operative contracts with
Calpine. Currently, Calpine markets our oil and gas under a marketing
services agreement (“Marketing Agreement”), whose term runs through June 30,
2009. We do not intend to extend or renew the Marketing Agreement
upon expiration. 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 a purchase and sale agreement and all interrelated agreements,
concurrently executed on or about July 7, 2005 (collectively, the “Purchase
Agreement”), except the gas sales agreement for the dedicated California
production which was amended and restated in connection with the parties’
settlement agreement dated October 22, 2008 (“Settlement Agreement”). The
Settlement Agreement, original gas purchase and sales contracts, the amended and
restated gas purchase and sales contract for the dedicated California
production, and the Marketing Agreement with Calpine are discussed further under
Part I. Item 3. Legal Proceedings, “Calpine Settlement” and “Marketing and
Customers.”
Our
Strategy
Our
strategy is to increase stockholder value by executing a business model that
delivers sustainable growth from unconventional onshore domestic
basins. We believe this strategy is appropriate for and consistent
with our longer-term view of the industry. However, we recognize that
there may be cycles, such as the current economic downturn, that could impact
our ability to execute this strategy fully on a short-term basis. Our
strategy is multi-pronged and emphasizes (i) identifying and growing
inventory in existing core properties, (ii) establishing new resource based
core areas, (iii) ongoing efficient exploitation and exploration activities,
(iv) completing acquisitions and selective divestitures, (v) maintaining
technical expertise, (vi) focusing on cost control and (vii) maintaining
financial flexibility. We seek to implement our strategy 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. Below is a discussion of the
key elements of our strategy:
Developing and
Extending Existing Core Properties. We have designated California, the
Rockies and South Texas as core areas and intend to build our asset base in
these areas through additional leasing and acquisitions where
applicable. As importantly, we intend to further develop the upside
potential of these core properties by conducting thorough resource assessments
of our existing assets, working over existing wells, drilling in-fill locations,
drilling step-out wells to expand known field outlines, testing and implementing
downspacing potential, recompleting and testing behind pipe pays and lowering
field line pressures through compression and optimization 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.
Ongoing Efficient
Exploitation and Exploration Activities. We intend to
generate growth in existing and new core areas with exploitation and exploration
inventory by efficiently applying technological and operational advantages
through repeatable 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 with
resource potential. We focus on opportunities with identified
inventory where we believe our reservoir management and operational expertise
will enhance the value and performance of the acquired properties through
repeatable drilling programs. Periodically, we also evaluate possible
divestitures of non-core 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 89%
for the year ended December 31, 2008 and helped us maximize field
recoveries. We 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, production, and
inventory.
Focusing on Cost
Control. We 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 activities within existing and
new resource-based core areas where we can achieve efficiencies through
economies of scale.
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, 2008, we had drawn $225.0
million and had $175.0 million available for borrowing under our revolving line
of credit. Additionally, we expect internally generated cash flow to provide
additional financial flexibility, allowing us to pursue our business strategy.
We intend to 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 facility, we entered into natural gas
fixed-price swaps for a portion of our expected production through
2010. As of December 31, 2008, 37% and 4% of our natural gas
production was hedged using swaps and costless collars, respectively, with
settlement in 2009, and 9% of our natural gas production was hedged with swaps
for settlement in 2010. 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
Settlement
On
December 20, 2005, Calpine Corporation and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the United States Bankruptcy
Court of the Southern District of New York (the “Bankruptcy
Court”). Two years later, on December 19, 2007, the Bankruptcy Court
confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on
January 31, 2008. During that period, on June 29, 2007, Calpine
commenced an adversary proceeding against the Company in the Bankruptcy Court
(the “Lawsuit”). Over the next fourteen months, the Company
vigorously disputed Calpine’s contentions in the Lawsuit, including any and all
allegations that it underpaid for Calpine’s oil and gas business.
On October
22, 2008, Calpine and the Company announced that they had entered into a
comprehensive settlement agreement (the “Settlement Agreement”) which, among
other things, would (i) resolve all claims in the Lawsuit, (ii) result in
Calpine conveying clean legal title on all remaining oil and gas assets to
Rosetta (except those properties subject to the preferential rights of third
parties who have indicated a desire to exercise their rights), (iii) settle all
pending claims the Company filed in the Calpine bankruptcy, (iv) modify and
extend a gas purchase agreement by which Calpine purchases the Company’s
dedicated production from the Sacramento Valley, California, and (v) formalize
the assumption by Calpine of the July 7, 2005 purchase and sale agreement
(together with all interrelated agreements, the “Purchase Agreement”) by which
Calpine’s oil and gas business was conveyed to the Company thus resulting in the
parties honoring their obligations under the Purchase Agreement on a
going-forward basis. The Settlement Agreement became effective when
the Bankruptcy Court entered its order on November 13, 2008, authorizing the
execution of the Settlement Agreement and the performance of the obligations set
forth therein. No objections or appeals to this order were filed or taken with
the Bankruptcy Court before or after the hearing on November 13, 2008, and it
became final on or about November 23, 2008.
The
parties completed this settlement pursuant to the terms of the Settlement
Agreement on December 1, 2008. The cash component of the settlement consisted of
$12.4 million payable in cash to Calpine to resolve all outstanding legal
disputes regarding various matters, including Calpine’s fraudulent conveyance
lawsuit. In addition, the Company paid $84.6 million under the Purchase
Agreement to close the original acquisition transaction of the producing
properties that were the subject of the lawsuit. This $84.6 million consisted of
$67.6 million, which the Company withheld from the purchase price at the closing
on July 7, 2005, related to non-consent properties (excluding the properties
subject to preferential rights) that were not conveyed to the Company at closing
on July 7, 2005, as well as $17.0 million for various disputed post-closing
adjustments under the terms of the Purchase Agreement, as amended by the
Bankruptcy Court order to remove the properties that had been subject to the
Petersen Production Company (“Petersen”) preferential rights as if
these properties had not been part of the Purchase Agreement.
As a
result of the conclusion of this settlement, the Company recorded a pre-tax
charge of $12.4 million in the fourth quarter of 2008, which is included in
Other Income (Expense) in the Consolidated Statement of
Operations. See Item 8. Financial Statements and
Supplementary Data, Note 11 – Commitments and Contingencies.
See Item
3. Legal Proceedings for further information regarding the final settlement with
Calpine.
Arbitration
between the Company and the successor to Pogo Producing
Company
On
October 27, 2008, the Company, Calpine and XTO Energy, Inc. (“XTO”), as the
successor to Pogo Producing Company (“Pogo”), agreed to a Title Indemnity
Agreement in which Calpine agreed to indemnify XTO for certain title disputes,
and the Company, Calpine and XTO agreed to dismissal of the arbitration
proceeding against the Company and release of Pogo’s proofs of claim. The
Company’s proofs of claim were resolved under its Settlement Agreement with
Calpine. XTO has dismissed with prejudice the arbitration against the
Company.
Our
Strengths
We
believe our key strengths are as follows:
High Quality
Asset Base. We own a geographically diversified asset base in key onshore
hydrocarbon basins. Approximately 95% of our reserves are natural gas
and almost all of our assets are located in the core areas of the Sacramento
Basin of California, the Rockies, and South Texas. In addition, we
have non-core positions in 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.
Resource
Assessment Capability and Inventory Generation. We have established
multi-disciplinary teams that are skilled at conducting comprehensive resource
assessments on a field and regional basis. This work is the
underpinning for indentifying and cataloging an inventory of low to
moderate risk opportunities providing us with multiple years of
drilling. At year end 2008, we had approximately 1,160 identified
projects in inventory, up about 150% compared to year end 2007. This
inventory, which includes proved undeveloped reserves, represents resources of
about 575 Bcfe on a net unrisked basis and about 300 Bcfe on a net risked
basis. We expect we will continue to add to our diversified portfolio
of non-proved resource inventory over time.
Operational
Control. We operate approximately 76% 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 28 years of experience in the energy industry with specific
experience in the areas where our core properties are located. In
November 2007, Randy L. Limbacher became our President and Chief Executive
Officer (“CEO”). Mr. Limbacher has more than 28 years of experience
in the energy industry, most recently serving as President, Exploration and
Production - Americas for ConocoPhillips. Since coming to
Rosetta, Mr. Limbacher has continued to hire experienced personnel with proven
track records of success in the unconventional resource business.
Proven Technical
and Land Personnel with Access to Technological Resources. Our technical
staff includes 48 geologists, geophysicists, landmen, engineers and technicians
with an average of over 15 years of relevant technical experience. Our staff has
experience in 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 89% for the year
ended December 31, 2008 and 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.
Our
Operating Areas
We own
core producing and non-producing oil and natural gas properties in proven or
prospective basins in California, the Rockies, South Texas, and various other
geographical areas in the United States. We also have non-core
positions in the State Waters of Texas and the Gulf of Mexico. In
each area, we are pursuing geological objectives and projects that are
consistent with our core strategy. For the year ended December 31, 2008, we have
drilled 184 gross and 152 net wells, with a success rate of 89%. The following
is a summary of our major operating areas.
California
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
located near the Northern California natural gas markets and has an established
natural gas gathering and pipeline infrastructure. We are one of the
largest producers and leaseholders in the basin.
As of
December 31, 2008, we owned approximately 69,000 net acres in the Rio Vista
Field and Sacramento Basin areas. We believe our acreage in the basin
holds significant low-risk, low-cost reserves, 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, 2008, our average net daily production from the Rio
Vista Field and surrounding fields in the Sacramento Basin was 43.6
MMcfe/d. In 2008, we drilled 14 gross wells of which 13 were
successful.
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 multiple 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, 2008, the average net daily production in the Rio
Vista Field was approximately 39 MMcfe/d. We drilled 12 wells in the Rio
Vista field in 2008; 11 of these were successful. Three wells
drilled in the southern portion of the field were successful in extending areas
in two reservoirs, the Lower Capay and the Martinez.
At
December 31, 2008, we had one rig actively drilling in the
field. There is one workover rig currently working on Rosetta wells
in the Rio Vista area. We plan to conduct approximately 36
workovers, recompletions or reactivation operations on field wells during
2009. Moreover, a majority of 2009 time and effort will be devoted to
resource assessments within the Rio Vista Gas Field. The evolution of
the studies will generate the future drilling and recompletion inventory for
2010 and beyond.
Sacramento Valley
Extension. We drilled two wells in
the Sacramento Valley Extension area in 2008, both were
successful. In 2009 we will continue to maintain operations through
base optimization, selective recompletions, and asset
rationalization.
Rockies
As of
December 31, 2008, we owned approximately 173,000 net acres in the
Rockies. Our production is concentrated in three basins: the DJ
Basin, San Juan Basin and Greater Green River Basin. Our average net
daily production for the year ended December 31, 2008 was 12.5
MMcfe/d. In 2008, we drilled 90 gross wells of which 84 were
successful.
DJ Basin, Colorado. As of December 31,
2008, we had a majority working interest in 111,290 net acres with 154 square
miles of 3D seismic data. In 2008, we drilled 76 locations, of which
70 were successful, and identified 500 additional drillable, 3D seismic
supported locations on these lands. In addition, one salt water
disposal well was drilled in 2008 and put into operation in the first quarter of
2009. For the year ended December 31, 2008, our average net daily
production from the DJ Basin was 7.6 MMcfe/d. Successful delineation
wells were drilled with newly acquired 3D seismic in Duke North, Duke, and Duke
South that will add to the production already established in the Republican
River, Vernon, SW Wray, and Sandy Bluffs areas.
San Juan Basin, New Mexico.
The San Juan Basin is the second most prolific gas basin in North America with
significant contribution coming from the Fruitland Coal Bed Methane (“CBM”)
trend. There is CBM production from depths of 1,600 feet surrounding our
leasehold. As of December 31, 2008, we had a 100% working interest position
in approximately 12,000 net acres. In May 2008, we purchased a 50%
working interest position in approximately 12,000 gross acres from North
American Petroleum Corporation USA, a subsidiary of Petroflow Energy
Ltd. In 2008, we drilled 14 CBM wells, all of which were
successful. For the year ended December 31, 2008, our average net
daily production from the San Juan Basin was 4.3 MMcfe/d. We
have identified 17 potential drillable locations on our acreage.
Pinedale, Wyoming. On
December 11, 2008, we purchased a 90% working interest in 1,280 acres of the
Pinedale field from Pinedale Energy LLC, a subsidiary of Constellation Energy
Group, Inc. We purchased 28 productive natural gas wells and 1 salt
water disposal well. We will study the field in 2009 for recompletion
and downspacing potential. At year end, our average net daily
production from Pinedale was 7.4 MMcfe/d.
Alberta Basin,
Montana. The Alberta Basin play is a westward analog of the
industry’s Bakken and Three Forks of the Williston Basin of Montana and North
Dakota. On December 24, 2008, Rosetta received approval from the
Bureau of Indian Affairs to option approximately 200,000 net acres located on
the Blackfeet Indian Reservation in Western Montana. Our plans for
2009 include detailed technical assessment, land consolidation, and drilling
test wells.
South
Texas
As of
December 31, 2008, we owned approximately 128,000 net acres in South
Texas. Our production in South Texas comes primarily from the Lobo,
Olmos, and Perdido sand trends, and averaged 54.5 MMcfe/d for the year ending
December 31, 2008. In 2008 we drilled 69 gross wells of which 57 were
successful. Additionally, we have acquired significant lease
positions in two emerging resource play areas: the Dinn Sand trend
and the Eagle Ford Shale trend.
Lobo Trend. We are
a significant producer in the South Texas Lobo Trend, with 320 square miles of
3-D seismic and 255 operated producing wells. Our working interests
range from 50% - 100%, but most of our acreage is 100% owned and
operated. In 2008, we added additional acres adjacent to our existing
acreage, adding additional drilling inventory. For the year ended
December 31, 2008, our average net daily production from the Lobo trend was 46.1
MMcfe/d. We have identified approximately 170 potential drilling
locations on our acreage. In 2008, we drilled 58 gross wells of which
48 were successful.
Discovered
in 1973, the Lobo trend of South Texas is a complex, highly faulted sand that
has produced over 8 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.
Olmos Trend. On
December 23, 2008, we closed on the acquisition of a 70% non-operated working
interest in 231 gross producing Olmos wells in the Olmos trend of
South Texas. Production from these wells was approximately 5 MMcfe/d
net at year end 2008.
Dinn Sand
Trend. In 2008, we acquired a significant acreage position
with approximately 100% operated working interest adjacent to our existing
Perdido development trend. This leasehold acquisition has
potential in the intermediate depth Dinn Sand trend. The Dinn Sand
has been sparsely developed with vertical wells, and has potential for
additional horizontal and vertical well development over most of the
leasehold. Additionally, much of the leasehold has potential for
extending the Perdido sand trend horizontal development from our adjacent
non-operated 50% working interest acreage to this operated 100% working interest
leasehold.
Eagle Ford Shale
Trend. In 2008, we acquired several sizable acreage tracts
with potential in the emerging shale gas play in the newly discovered Eagle Ford
Shale trend. Along with acreage acquired in previous years, and the
deep rights acquired with the Olmos production acquisition, we now have
approximately 25,000 net acres in the Eagle Ford Shale trend. Most of
this acreage also has potential in the Austin Chalk and Edwards
formations.
Perdido Sand Trend. We own a
50% non-operated working interest 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. We plan to continue
to coordinate with the operator to improve horizontal and vertical drilling
techniques to lower cost and increase performance. For the year ended
December 31, 2008, our average net daily production was 8.3 MMcfe/d from 37
producing wells (24 horizontal and 13 vertical). We participated in the drilling
of seven gross wells in 2008, all of which were successful. We
have identified approximately 60 potential drilling locations on our
acreage.
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 well in Live Oak County, Texas in the
fourth quarter of 2007 and tested the well in December 2007. The well
was completed with first production commencing 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 41,000 net acres under
lease with an average non-operated working interest of
47%.
Texas
State Waters
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 2008, we drilled 4 gross wells, of which
3 were successful. Net production averaged 11.8 MMcfe/d during
2008. The field suffered some damage during Hurricane Ike in
September 2008. Temporary repairs allowed bringing the wells back on
line by October 2008, with permanent repairs to facilities and production
equipment completed by year end. We currently hold interest in
approximately 6,000 net acres with 70 square miles of 3-D seismic
data.
Gulf
of Mexico
Federal Waters. We
own working interests in 12 offshore blocks ranging from 20% to 100% working
interest with approximately 29,000 net acres. For the year ended
December 31, 2008, our average net daily production from these blocks was 12
MMcfe/d.
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, 2008
|
|
|
|
Natural
Gas
(Bcf)
|
|
|
Oil
(MBbls)
|
|
|
Equivalents
(Bcfe)
|
|
California
|
|
|
15.8 |
|
|
|
31.4 |
|
|
|
15.9 |
|
Rockies
|
|
|
4.5 |
|
|
|
6.1 |
|
|
|
4.6 |
|
South
Texas
|
|
|
19.1 |
|
|
|
132.8 |
|
|
|
19.9 |
|
Other
Onshore
|
|
|
3.6 |
|
|
|
128.9 |
|
|
|
4.4 |
|
Texas
State Waters
|
|
|
3.5 |
|
|
|
143.5 |
|
|
|
4.4 |
|
Gulf
of Mexico
|
|
|
3.8 |
|
|
|
103.7 |
|
|
|
4.4 |
|
|
|
|
50.3 |
|
|
|
546.4 |
|
|
|
53.6 |
|
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, 2008, we had 398.2 Bcfe of proved oil and natural gas
reserves, including 376.5 Bcf of natural gas and 3,603 MBbls of oil and
condensate. Using prices as of December 31, 2008, the estimated
standardized measure of discounted future net cash flows was $839
million. The following table sets forth, by operating area, a summary
of our estimated net proved reserve information as of December 31,
2008:
|
|
Estimated
Proved Reserves at December 31, 2008 (1)
|
|
|
|
Developed
(Bcfe)
|
|
|
Undeveloped
(Bcfe)
|
|
|
Total
(Bcfe)
|
|
|
Percent
of Total Reserves
|
|
California
|
|
|
89.0 |
|
|
|
21.9 |
|
|
|
110.9 |
|
|
|
28 |
% |
Rockies
|
|
|
73.0 |
|
|
|
5.2 |
|
|
|
78.2 |
|
|
|
20 |
% |
South
Texas
|
|
|
117.7 |
|
|
|
42.0 |
|
|
|
159.7 |
|
|
|
40 |
% |
Other
Onshore
|
|
|
21.8 |
|
|
|
- |
|
|
|
21.8 |
|
|
|
6 |
% |
Texas
State Waters
|
|
|
9.9 |
|
|
|
- |
|
|
|
9.9 |
|
|
|
2 |
% |
Gulf
of Mexico
|
|
|
16.0 |
|
|
|
1.7 |
|
|
|
17.7 |
|
|
|
4 |
% |
Total
|
|
|
327.4 |
|
|
|
70.8 |
|
|
|
398.2 |
|
|
|
100 |
% |
___________________________________
|
(1)
|
These
estimates are based upon a reserve report prepared by Netherland
Sewell & Associates, Inc. (hereafter “Netherland Sewell”),
independent petroleum engineers, using internally developed reserve
estimates and criteria in compliance with the Securities and Exchange
Commission (“SEC”) guidelines. See Item
7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations “Critical Accounting Policies and Estimates” and
Item 8. Financial Statements and Supplementary Data “Supplemental Oil and
Gas Disclosures.”
|
2008
Capital Expenditures
The
following table summarizes information regarding development and exploration
capital expenditures for the years ended December 31, 2008, 2007
and 2006:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Capital
Expenditures by Operating Area:
|
|
|
|
|
|
|
|
|
|
California
|
|
$ |
42,429 |
|
|
$ |
58,493 |
|
|
$ |
39,691 |
|
Rockies
|
|
|
25,015 |
|
|
|
23,904 |
|
|
|
15,299 |
|
South
Texas
|
|
|
94,567 |
|
|
|
105,301 |
|
|
|
77,882 |
|
Other
Onshore
|
|
|
12,927 |
|
|
|
29,796 |
|
|
|
13,578 |
|
Texas
State Waters
|
|
|
8,541 |
|
|
|
27,000 |
|
|
|
13,028 |
|
Gulf
of Mexico
|
|
|
422 |
|
|
|
28,523 |
|
|
|
17,958 |
|
Leasehold
|
|
|
17,883 |
|
|
|
8,838 |
|
|
|
16,383 |
|
Acquisitions
|
|
|
115,074 |
|
|
|
38,656 |
|
|
|
35,105 |
|
Delay
rentals
|
|
|
1,451 |
|
|
|
1,409 |
|
|
|
728 |
|
Geological
and geophysical/seismic
|
|
|
4,571 |
|
|
|
4,422 |
|
|
|
3,748 |
|
Total
capital expenditures (1)
|
|
$ |
322,880 |
|
|
$ |
326,342 |
|
|
$ |
233,400 |
|
___________________________________
|
(1)
|
Capital
expenditures for the year ended December 31, 2008 exclude capitalized
internal costs directly identified with acquisition, exploration and
development activities of $7.1 million, capitalized interest of $1.4
million and corporate other capital costs of $3.0 million. Capital
expenditures for the year ended December 31, 2007 exclude 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 exclude capitalized
internal costs of $3.4 million, capitalized interest of $2.1 million and
corporate other capital 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.
|
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, 2008. “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
|
|
|
Developed
Acres
|
|
|
Productive
Wells (1)
|
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
|
Gross
|
|
|
Net
|
|
California
|
|
|
31,829 |
|
|
|
23,587 |
|
|
|
53,786 |
|
|
|
44,829 |
|
|
|
163 |
|
|
|
150 |
|
Rockies
|
|
|
167,227 |
|
|
|
143,709 |
|
|
|
37,105 |
|
|
|
28,667 |
|
|
|
249 |
|
|
|
216 |
|
South
Texas
|
|
|
54,240 |
|
|
|
45,399 |
|
|
|
140,635 |
|
|
|
82,208 |
|
|
|
523 |
|
|
|
401 |
|
Other
Onshore
|
|
|
33,065 |
|
|
|
21,317 |
|
|
|
55,128 |
|
|
|
19,881 |
|
|
|
304 |
|
|
|
51 |
|
Texas
State Waters
|
|
|
5,706 |
|
|
|
2,709 |
|
|
|
9,978 |
|
|
|
3,259 |
|
|
|
8 |
|
|
|
2 |
|
Gulf
of Mexico
|
|
|
7,500 |
|
|
|
5,000 |
|
|
|
41,994 |
|
|
|
24,386 |
|
|
|
7 |
|
|
|
5 |
|
|
|
|
299,567 |
|
|
|
241,721 |
|
|
|
338,626 |
|
|
|
203,230 |
|
|
|
1,254 |
|
|
|
825 |
|
___________________________________
|
(1)
|
Offshore
productive wells are based on intervals rather than well
bores.
|
The
following table shows our interest in undeveloped acreage as of
December 31, 2008 which is subject to expiration in 2009, 2010, 2011, and
thereafter.
2009
|
|
2010
|
|
2011
|
|
Thereafter
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
|
Gross
|
|
Net
|
36,617
|
|
31,249
|
|
63,476
|
|
53,145
|
|
89,151
|
|
70,184
|
|
110,323
|
|
87,143
|
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
|
|
2008
|
|
|
3.0 |
|
|
|
1.0 |
|
|
|
4.0 |
|
|
|
160.0 |
|
|
|
20.0 |
|
|
|
180.0 |
|
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 |
|
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
|
|
2008
|
|
|
1.9 |
|
|
|
1.0 |
|
|
|
2.9 |
|
|
|
132.7 |
|
|
|
15.9 |
|
|
|
148.6 |
|
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 |
|
Marketing
and Customers
Our
amended and restated natural gas purchase and sales contract with Calpine Energy
Services (“CES”) dated as of October 22, 2008, for the dedicated California
production was approved by the Bankruptcy Court and executed by the parties
pursuant to the terms of the Settlement Agreement. The term of this amended and
restated contract with CES runs through December 2019. The ten year
right of first refusal provision, which was formerly part of this agreement, has
been eliminated. Pursuant to the terms of this amended and restated contract
with CES, 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. For the month of
December 2008, this dedicated California production comprised approximately
29% of our current overall daily equivalent production.
Under the
terms of this amended and restated contract with CES and our other spot natural
gas purchase and sale agreements with Calpine, cash payment for all natural gas
volumes that are contractually sold to CES 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 contracts, we are not obligated to
continue to sell our production to CES and these sales may cease immediately. We
would then be in a position to market this natural gas production to other
parties. CES has 60 days to pay amounts owed to us, at which time, provided CES
has fully cured such payment default, we are obligated under the contract to
resume natural gas sales to CES. We believe that Calpine’s bankruptcy and their
emergence from bankruptcy have not had a significant effect on our ability to
sell our natural gas at market prices.
We may
market our natural gas production in California, which is not subject to this
amended and restated contract with CES, to parties other than
Calpine. All of our other production (other than our dedicated
California production being sold pursuant to this amended and restated contract
with CES at market pricing) is sold to various purchasers, including CES, on a
competitive basis. Additionally, Calpine Producer Services, L.P., an
affiliate of Calpine Corporation, is under contract through June 30, 2009 to
provide us with administrative services in connection with our marketing efforts
for all of our oil and gas production in accordance with the contract
terms. We do not intend to extend or renew this marketing contract
upon expiration, rather we intend to market all of our oil and gas production
ourselves at the conclusion of this contract and our expanding our internal
capabilities in this regard.
Major
Customers
For the
year ended December 31, 2008, we had one major customer, CES, which accounted
for, on an aggregate basis, approximately 61% 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 than we do.
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. 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 legislation 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
material 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 types
of legislation affecting our business.
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 stringent federal, state and local statutes, rules and regulations
concerning occupational safety and health and protection of wildlife habitat and
the natural environment. We have made and will continue to make
expenditures in our efforts to comply with these requirements. At
December 31, 2008, these estimated future expenditures for environmental control
facilities were not material. In this regard, we believe that we
currently hold all up-to-date permits, registrations and other authorizations to
the extent they are required of 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 unavailable
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. We carry limited property insurance for loss or
damage caused by earthquakes, and our energy package insurance, including
property insurance, is limited to $15 million in the aggregate for any single
named windstorm with a $1 million retention.
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 2008, we filed estimates of our oil and gas reserves
as of December 31, 2007 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, 2007. For information concerning proved
natural gas and crude oil reserves, refer to Item 8. Financial Statements
and Supplementary Data, Supplemental Oil and
Gas Disclosures.
Employees
As of
February 20, 2009, we have 186 full time employees. We also contract for the
services of consultants involved in land, regulatory, accounting, financial,
legal and other disciplines as needed. As of February 20, 2009, we
have contracted approximately 45 independent consultants. 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.
Available
Information
Through
our website, http://www.rosettaresources.com, you can access, free of
charge, our
filings with the SEC, including our annual reports on Form 10-K, quarterly
reports on Form 10-Q, current reports on Form 8-K, and amendments to those
reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange
Act, our Code of Business Conduct and Ethics, Nominating and Corporate
Governance Committee Charter, Audit Committee Charter, and Compensation
Committee Charter. You may also read and copy any materials that we
file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Room
1580, Washington, D.C. 20549. You may obtain information on the
operation of the Public Reference Room 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 http://www.sec.gov.
Broad
industry or economic factors may adversely affect the timing of and extent to
which the Company can effectively implement its strategy shift to an onshore
unconventional resource player.
Our
strategy shift is an important element of positioning the Company for more
predictable, sustainable future performance. In conjunction with
pursuing this shift, the Company recognizes that several factors could impact
our ability to execute the shift, including: (i) a sustained downturn of
commodity prices, (ii) a lack of inventory potential within existing assets,
(iii) an inability to attract and retain the personnel necessary to implement an
unconventional resource business model, and (iv) a lack of access to
credit. The Company has processes in place to track and monitor these
trends on an ongoing basis. At this time, the Company believes the
rationale and the goals for the strategy shift are intact; however, current
market conditions could impact the pace of the planned shift.
Recent
changes in the financial and credit markets may impact economic growth and oil
and gas prices may continue to be adversely affected by general economic
conditions.
Based on
a number of economic indicators, it appears that growth in global economic
activity has slowed substantially. At the present time, the rate at
which the global economy will slow has become increasingly
uncertain. A continued slowing of global economic growth, and access
to credit markets, and, in particular, in the United States or China, will
likely continue to reduce demand for oil and natural gas. A
reduction in the demand for and the resulting lower prices of oil and natural
gas could adversely affect our results of operations.
The
current deterioration in the credit markets, combined with a decline in
commodity prices, may impact our capital expenditure level and also our
counterparty risk.
While we
seek to fund our capital expenditures primarily from cash flows from operating
activities, we have in the past also drawn on unused capacity under our existing
revolving credit facility for capital expenditures. While we have not
received any indication from our lenders that our ability to draw on our
existing revolving credit facility has been restricted, it is possible that our
borrowing base, which is based on our oil and gas reserves and is subject to
review and adjustment on a semi-annual basis, with the next review scheduled to
begin on March 2, 2009, and other interim adjustments, may be reduced when it is
reviewed. In the event that our borrowing base is reduced,
outstanding borrowings in excess of the revised base will be due
immediately. As we do not have a substantial amount of unpledged
property, we may not have the financial resources to make the mandatory
prepayments. A reduction in our ability to borrow under our existing
revolving credit facility, combined with a reduction in cash flow from operating
activities resulting from a decline in commodity prices, may require us
to reduce our capital expenditures further, which may in turn adversely
affect our ability to carry out our business plan and execute our
programs. Furthermore, if we lack the resources to dedicate
sufficient capital expenditures to our existing oil and gas leases, we may be
unable to produce adequate quantities of oil and gas to retain these leases and
they may expire due to a lack of production. The loss of a sufficient
number of leases could have a material adverse effect on our results of
operations.
Additionally,
while we believe that our existing production is adequately hedged with credit
worthy counterparties, continued deterioration in the credit markets may impact
the credit ratings of our current and potential counterparties and affect their
ability to fulfill their existing obligations to us and their willingness to
enter into future transactions with us.
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. Additionally, our results are subject to commodity price
fluctuations related to seasonal and market conditions and reservoir and
production risks.
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:
|
–
|
Domestic
and foreign supply of oil and gas;
|
|
–
|
Price
and quantity of foreign imports;
|
|
–
|
Actions
of the Organization of Petroleum Exporting Countries and state-controlled
oil companies relating to oil price and production
controls;
|
|
–
|
Conservation
of resources;
|
|
–
|
Regional
price differentials and quality differentials of oil and natural
gas;
|
|
–
|
Domestic
and foreign governmental regulations, actions and
taxes;
|
|
–
|
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;
|
|
–
|
Weather
conditions and natural disasters;
|
|
–
|
Technological
advances affecting oil and natural gas
consumption;
|
|
–
|
Overall
U.S. and global economic
conditions;
|
|
–
|
Price
and availability of alternative
fuels;
|
|
–
|
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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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 continued weakness 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. Recent
deterioration in overall economic conditions and tightening of credit markets
may increase the risk that contractual counterparties may fail to perform.
Further deterioration in economic conditions in 2009 could result in an even
greater risk of non-performance by market participants including our
counterparties which could further impact our financial position.
We
sell a significant amount of our production to one customer.
In
connection with the Acquisition and now the Settlement Agreement, we have
entered into an amended and restated natural gas purchase and sale contract with
CES whose term runs through December 2019. Under this amended and restated
contract with CES, 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. For the month of December 2008, this
dedicated California production comprised approximately 29% of our current
overall production based on an equivalent unit 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 amended and restated contract with CES and spot agreements with CES, all
natural gas volumes that are contractually sold to CES are collateralized by CES
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 CES,
we could be exposed to the loss of up to four days of natural gas sales revenue
under these contracts, which at prices and volumes in effect as of
December 31, 2008 would be approximately $2.5 million.
Unless
we replace our oil and natural gas reserves, our reserves and production will
decline.
Our
future oil and natural gas production depends on our success in finding or
acquiring additional reserves. If we fail to replace reserves through drilling
or acquisitions, our level of production and cash flows will be affected
adversely. In general, production from oil and natural gas properties declines
as reserves are depleted, with the rate of decline depending on reservoir
characteristics. Our total proved reserves decline as reserves are produced. Our
ability to make the necessary capital investment to maintain or expand our asset
base of oil and natural gas reserves would be impaired to the extent cash flow
from operations is reduced and external sources of capital become limited or
unavailable. We may not be successful in exploring for, developing or acquiring
additional reserves.
We
will require additional capital to fund our future activities. If we fail to
obtain additional capital, we may not be able to implement fully our business
plan, which could lead to a decline in reserves.
Future
projects and acquisitions 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. If we are unable to comply with these covenants, our
lenders could accelerate the repayment of our indebtedness.
The terms
of our credit facilities subject us to a number of covenants that impose
restrictions on us, including our ability to incur indebtedness and liens, make
loans and investments, make capital expenditures, sell assets, engage in
mergers, consolidations and acquisitions, enter into transactions with
affiliates, enter into sale and leaseback transactions, change our lines of
business and pay dividends on our common stock. We will also be required by the
terms of our credit facilities to comply with financial covenant
ratios. A more detailed description of our credit facilities is
included in Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations—Liquidity and Capital Resources and the
footnotes to the Consolidated Financial Statements.
A breach
of any of the covenants imposed on us by the terms of our indebtedness,
including the financial covenants under our credit facilities, could result in a
default under such indebtedness. In the event of a default, the lenders for our
revolving credit facility could terminate their commitments to us, and they and
the lenders of our second lien term loan could accelerate the repayment of all
of our indebtedness. In such case, we may not have sufficient funds to pay the
total amount of accelerated obligations, and our lenders under the credit
facilities could proceed against the collateral securing the facilities, which
is substantially all of our assets. 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. 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, independent petroleum engineers Netherland Sewell’s reserve report for
year end 2008 includes the downward revision of 64 Bcfe of proved reserves and 8
Bcfe due to year-end commodity prices, or approximately 17% of previously
estimated reserves. 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. Our reserves as of December 31, 2008 were
based on West Texas Intermediate oil prices of $41.00 per Bbl and Henry Hub gas
prices of $5.71 per MMbtu compared to $92.50 and $6.80, respectively, at
December 31, 2007. 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 has resulted in a
write-down of our estimated net reserves and may result in a write-down in the
future if commodity prices continue to decline.
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. 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, a 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, 2008, we recognized a non-cash, pre-tax ceiling
test impairment of $205.7 million and $238.7 million in the third and fourth
quarters of 2008, respectively. Due to the volatility of commodity
prices, should natural gas prices continue to decline in the future, it is
possible that an additional write-down could occur.
In
addition, write-downs of proved oil and natural gas properties may occur if we
experience substantial downward adjustments to our estimated proved
reserves. For example, we recognized a downward revision to our
proved reserves in the third and fourth quarters of 2008. As we
are continuing to evaluate and test our asset base, it is possible that we may
recognize additional revisions to our proved reserves in the
future.
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 upon 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.
The
ultimate outcome of any 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. 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. If oil and gas
prices increase in the future, increasing levels of exploration and production
could result in response to these stronger prices, and as a result, the demand
for oilfield services could rise, and the costs of these services could
increase, 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 could 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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Ability
or impediments to conducting thorough due diligence
activities;
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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 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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Availability
of required performance bonds and
insurance;
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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, result in financial losses or reduce
our income .
We have
entered into natural gas price hedging arrangements with respect to a portion of
our expected production through 2010. As of December 31, 2008, 37% and 4% of our
natural gas production was hedged using swaps and costless collars,
respectively, with settlement in 2009, and 9% of our natural gas production was
hedged with swaps for settlement in 2010, based on anticipated future gas
production. 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. Our current hedge positions are with counterparties that
are lenders in our credit facilities. Our lenders are comprised of banks and
financial institutions that could default or fail to perform under our
contractual agreements. A default under any of these agreements could negatively
impact our financial performance.
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 may not receive the benefit of the lower interest
rates.
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, 2008, 51,748,920 shares of common stock were issued, including
1,434,430 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, 716,991 shares
had vested as of December 31, 2008 and the remaining shares will vest no later
than 2012. Pursuant to our amended 2005 Long-Term Incentive Plan, we have
reserved 4,950,000 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 1,245,875 options to purchase common stock issued to
certain employees and directors, of which 304,119 have been exercised as of
December 31, 2008. 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.
Item 1B. Unresolved Staff Comments
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 and lease a third floor. 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 interfere with our use of the
properties in the operation of our business.
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.
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
Settlement
On
December 20, 2005, Calpine filed for protection under the federal bankruptcy
laws. Two years later, on December 19, 2007, the Bankruptcy Court
confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on
January 31, 2008. During that period, on June 29, 2007, Calpine
commenced the Lawsuit. Over the next fourteen months, the Company
vigorously disputed Calpine’s contentions in the Lawsuit, including any and all
allegations that it underpaid for Calpine’s oil and gas business.
On October
22, 2008, Calpine and the Company announced that they had entered into the
Settlement Agreement which, among other things, would (i) resolve all claims in
the Lawsuit, (ii) result in Calpine conveying clean legal title on all remaining
oil and gas assets to Rosetta (except those properties subject to the
preferential rights of third parties who have indicated a desire to exercise
their rights), (iii) settle all pending claims the Company filed in the Calpine
bankruptcy, (iv) modify and extend a gas purchase agreement by which Calpine
purchases the Company’s dedicated production from the Sacramento Valley,
California, and (v) formalize the assumption by Calpine of the July 7, 2005
purchase and sale agreement (together with all interrelated agreements, the
“Purchase Agreement”) by which Calpine’s oil and gas business was conveyed to
the Company thus resulting in the parties honoring their obligations under the
Purchase Agreement on a going-forward basis. The Settlement Agreement
became effective when the Bankruptcy Court entered its order on November 13,
2008, authorizing the execution of the Settlement Agreement and the performance
of the obligations set forth therein. No objections or appeals to this order
were filed or taken with the Bankruptcy Court before or after the hearing on
November 13, 2008, and it became final on or about November 23,
2008.
The
parties completed this settlement pursuant to the terms of the Settlement
Agreement on December 1, 2008. The cash component of the settlement
consisted of $12.4 million payable in cash to Calpine to resolve all outstanding
legal disputes regarding various matters, including Calpine’s fraudulent
conveyance lawsuit. In addition, the Company paid $84.6 million under the
Purchase Agreement to close the original acquisition transaction of the
producing properties that were the subject of the lawsuit. This $84.6 million
consisted of $67.6 million, which the Company withheld from the purchase price
at the closing on July 7, 2005, related to non-consent properties (excluding the
properties subject to the Petersen preferential rights) that were not conveyed
to the Company at closing on July 7, 2005, as well as $17.0 million for various
disputed post-closing adjustments under the terms of the Purchase Agreement, as
amended by the Bankruptcy Court order to remove the properties that had been
subject to the Petersen preferential rights, as if these properties had not been
part of the Purchase Agreement.
As a
result of the conclusion of this settlement, the Company recorded a pre-tax
charge of $12.4 million in the fourth quarter of 2008, which is included in
Other Income (Expense) in the Consolidated Statement of Operations.
Arbitration
between the Company and the successor to Pogo Producing
Company
On
October 27, 2008, the Company, Calpine and XTO, as the successor to Pogo, agreed
to a Title Indemnity Agreement in which Calpine agreed to indemnify XTO for
certain title disputes, and the Company, Calpine and XTO agreed to dismissal of
the arbitration proceeding against the Company and release of Pogo’s proofs of
claim. The Company’s proofs of claim were resolved within the framework of the
Settlement Agreement with Calpine, which was approved by the Bankruptcy Court
and an order issued in this regard. XTO has dismissed with prejudice
the arbitration against the Company.
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 2008.
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.
The
following table sets forth for the 2008 and 2007 periods indicated the high and
low sale prices of our common stock:
2008
|
|
2007
|
|
|
|
High
|
|
|
Low
|
|
|
|
High
|
|
|
Low
|
|
January
1 - March 31
|
|
$ |
21.42 |
|
|
$ |
16.20 |
|
January
1 - March 31
|
|
$ |
21.07 |
|
|
$ |
17.66 |
|
April
1 - June 30
|
|
|
29.65 |
|
|
|
19.15 |
|
April
1 - June 30
|
|
|
25.00 |
|
|
|
20.74 |
|
July
1 - September 30
|
|
|
29.20 |
|
|
|
16.67 |
|
July
1 - September 30
|
|
|
21.97 |
|
|
|
15.67 |
|
October
1 - December 31
|
|
|
18.23 |
|
|
|
5.97 |
|
October
1 - December 31
|
|
|
20.84 |
|
|
|
17.69 |
|
The
number of shareholders of record on February 24, 2009 was approximately 10,700.
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. Our Senior Secured
Revolving Line of Credit agreement restricts our ability to pay cash dividends
on our common stock. See Item 8. Financial Statements and
Supplementary Data Note 10 – Long-Term Debt.
The
following table sets forth certain information with respect to repurchases of
our common stock during the three months ended December 31, 2008:
Period
|
|
Total
Number of Shares Purchased (1)
|
|
|
Average
Price Paid per Share
|
|
|
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
|
|
|
Maximum
Number (or Approximate Dollar Value) of Shares that May yet Be Purchased
Under the Plans or Programs
|
|
October
1 - October 31
|
|
|
2,563 |
|
|
$ |
12.71 |
|
|
|
- |
|
|
|
- |
|
November
1 - November 30
|
|
|
1,669 |
|
|
|
10.02 |
|
|
|
- |
|
|
|
- |
|
December
1 - December 31
|
|
|
82 |
|
|
|
6.99 |
|
|
|
- |
|
|
|
- |
|
___________________________________
|
(1)
|
All
of the shares were surrendered by our 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 performance graph and related information shall not be deemed
“soliciting material” or to be “filed” with the Securities and Exchange
Commission, nor shall such information be incorporated by reference into any
future filing under the Securities Act of 1933 or Securities Exchange Act of
1934, each as amended, except to the extent that the Company specifically
incorporates it by reference into such filing.
The
following common stock performance graph shows the performance of Rosetta
Resources Inc. common stock up to December 31, 2008. As required by
applicable rules of the Securities Exchange Commission, the performance graph
shown below was prepared based on the following assumptions:
|
·
|
A
$100 investment was made in Rosetta Resources Inc. common stock at the
opening trade price of $19.00 per share on February 13, 2006 (the first
full trading day following the Company’s initial public offering of its
common stock), and $100 was invested in each of the Standard & Poor’s
500 Index (S&P 500), a selected Peer Group (described below), and the
Standard & Poor’s MidCap 400 Oil & Gas Exploration &
Production Index (S&P 400 E&P) at the closing price on February
10, 2006.
|
|
·
|
All
dividends are reinvested for each measurement
period.
|
The seven
companies that comprise the selected 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). In 2008, we changed
from using a selected Peer Group to the S&P 400 E&P Index because this
published index is widely recognized in our industry and includes a
representative group of independent peer companies (weighted by market capital)
that are engaged in comparable exploration, development and production
operations. In the future, we will not include the Peer Group in our
analysis.
Total
Return Among Rosetta Resources Inc., the S&P 500 Index, the S&P 400
O&G E&P Index, and our Peer Group
|
|
2/13/2006
(1)
|
|
|
12/31/2006
|
|
|
12/31/2007
|
|
|
12/31/2008
|
|
ROSE
|
|
$ |
100.00 |
|
|
$ |
98.26 |
|
|
$ |
104.37 |
|
|
$ |
37.26 |
|
Peer
Group
|
|
$ |
100.00 |
|
|
$ |
98.01 |
|
|
$ |
148.08 |
|
|
$ |
105.67 |
|
S&P
500
|
|
$ |
100.00 |
|
|
$ |
111.94 |
|
|
$ |
115.89 |
|
|
$ |
71.29 |
|
S&P400
O&G E&P
|
|
$ |
100.00 |
|
|
$ |
103.01 |
|
|
$ |
148.46 |
|
|
$ |
67.48 |
|
___________________________________
(1)
February 13, 2006 was the first full trading day following the effective date of
the Company’s registration statement filed in connection with the public
offering of its common stock.
Item 6. Selected Financial Data
The
following table sets forth our selected financial data. For the years
ended December 31, 2008, 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 year ended December 31, 2004
(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 Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations and the audited Consolidated Financial Statements and related notes
included elsewhere in this Form 10-K.
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,
|
|
|
|
2008
(2)
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
2005
|
|
|
2004
(1) (2)
|
|
|
|
(In
thousands, except per share data)
|
|
Operating
Data:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
revenue
|
|
$ |
499,347 |
|
|
$ |
363,489 |
|
|
$ |
271,763 |
|
|
$ |
113,104 |
|
|
$ |
103,831 |
|
|
$ |
248,006 |
|
Income
(loss) from continuing operations
|
|
|
(188,110 |
) |
|
|
57,205 |
|
|
|
44,608 |
|
|
|
17,535 |
|
|
|
18,681 |
|
|
|
(78,836 |
) |
Net
income (loss)
|
|
|
(188,110 |
) |
|
|
57,205 |
|
|
|
44,608 |
|
|
|
17,535 |
|
|
|
18,681 |
|
|
|
(10,396 |
) |
Income
(loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) from continuing operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
(3.71 |
) |
|
|
1.14 |
|
|
|
0.89 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(1.58 |
) |
Diluted
|
|
|
(3.71 |
) |
|
|
1.13 |
|
|
|
0.88 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(1.58 |
) |
Net
income (loss)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
(3.71 |
) |
|
|
1.14 |
|
|
|
0.89 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(0.21 |
) |
Diluted
|
|
|
(3.71 |
) |
|
|
1.13 |
|
|
|
0.88 |
|
|
|
0.35 |
|
|
|
0.37 |
|
|
|
(0.21 |
) |
Cash
dividends declared per common share
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Balance
Sheet Data (At the end of the Period)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets
|
|
|
1,154,378 |
|
|
|
1,357,214 |
|
|
|
1,219,405 |
|
|
|
1,119,269 |
|
|
|
- |
|
|
|
656,528 |
|
Long-term
debt
|
|
|
300,000 |
|
|
|
245,000 |
|
|
|
240,000 |
|
|
|
240,000 |
|
|
|
- |
|
|
|
- |
|
Stockholders'
equity/owner's net investment
|
|
|
726,372 |
|
|
|
872,955 |
|
|
|
822,289 |
|
|
|
715,423 |
|
|
|
- |
|
|
|
223,451 |
|
____________________________________
|
(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 $444.4 million and a $202.1 million non-cash, pre-tax impairment charge
for the years ended December 31, 2008 and 2004,
respectively.
|
Item 7. Management’s Discussion and Analysis of Financial
Condition and Results of Operations
Overview
Rosetta
has delivered production growth by executing a business model based
predominantly upon conventional exploration and exploitation. The Company
actively pursued opportunities in conventional basins and plays characterized by
higher decline rates. In early 2008, we began a strategic shift toward a
business model that we believed could generate more sustainable,
predictable performance over time. Accordingly, we have been on a path to
de-emphasize high-decline rate, conventional programs in the Gulf of Mexico and
Texas State Waters, while focusing on building positions and programs in
unconventional onshore domestic basins. These basins are characterized by
having lower hydrocarbon risk project inventory and repeatable programs, which
the Company believes can generate more sustainable, predictable results.
Consistent with the nature of unconventional resources, we would expect annual
production growth rates to moderate compared to historical production growth
rates as we shift to more resource-driven projects and focus on drilling
inventory generation. Our strategy shift will be accompanied by goals to
deliver, over time, both acceptable rates of production growth, as well as
growth in proved, probable and possible reserves in excess of historical
performance. The timing of and extent to which we can implement this
strategy shift will depend on several factors, most notably commodity prices and
access to credit.
Under
more typical price scenarios, we believe we can successfully implement our
strategy shift because of some inherent strengths. Of note, we believe our
core existing onshore assets have upside that has not been fully analyzed
through an unconventional resource lens. We think this approach could yield
additional inventory for the Company over time. In addition, we have an
experienced workforce and management team with background in unconventional
resource operations. Finally, we have a financial and capital allocation
approach that we believe allows us to adapt to the inevitable industry
cycles and the current economic downturn. These factors do not ensure our
success in executing our strategy shift, but we believe they provide a
competitive advantage towards executing our strategy shift over the longer
term.
Our plan
for implementing the strategy shift that is underway is to pursue, over time,
both organic and inorganic opportunities that meet Rosetta’s criteria for
funding, particularly inventory potential and attractive financial
returns. In 2008, we began several studies to test organic concepts in
areas where we currently have assets for the purpose of identifying
possible upside and inventory. We also began studying new domestic basins where
we believe Rosetta can compete successfully. While we have a preference
for organic opportunities, we are also expanding our capability to evaluate and
pursue acquisition opportunities that make sense for Rosetta. We believe this
balanced approach is needed for long-term success; however, it is not our
intention or desire to pursue acquisitions solely for the sake of
growth. Our ability to execute organic and inorganic activities will
depend on market conditions.
On
October 22, 2008, we signed the Settlement Agreement with
Calpine. This settlement resolved all disputes between the parties,
whether relating to the oil and gas property purchase, Rosetta’s proofs of claim
in the bankruptcy and its counter claims, or otherwise and was recorded as a
pre-tax charge to income in the amount of $12.4 million. In addition,
we paid $84.6 million to close the original 2005 acquisition transaction of the
producing properties that were the subject of the Lawsuit. This $84.6
million consisted of $67.6 million which we withheld from the purchase price
related to properties that were not conveyed to Rosetta, as well as $17.0
million for post-closing adjustments.
During
2008, our technical teams conducted a comprehensive review of several detailed
field studies. Based upon these studies, and in coordination with our
independent reserve engineers, we recognized a downward revision of 64 Bcfe of
proved reserves, or approximately 15% of previously estimated
reserves. We believe that our year-end reserves reflect our
comprehensive updated technical view of field performance. In
addition, we recognized 8 Bcfe of downward revisions due to year-end
commodity prices and a cumulative non-cash ceiling test impairment charge of
$444.4 million on a pre-tax basis, and $278.9 million net of tax.
With the
Calpine Settlement and known reserve revisions behind us, we enter 2009 in a
position to execute our business plan and effect our desired goals, subject to
economic and market factors. We believe that we now have greater operating
control and latitude over critical activities, such as rationalizing our
portfolio, attracting technical talent, pursuing acquisitions that fit our
strategy, and building sustainable project inventory. Our preliminary
2009 capital spending budget of $250 million was announced in the fourth quarter
of 2008. At that time, we indicated that we believed the program
could be funded internally at an average gas price of $7 per Mcf. We
also indicated that we could expect to maintain annual production volumes in the
range of 140 – 150 MMcfe/day for that level of spending. Given the
current pervasive commodity price and economic downturn, our capital spending
and production guidance are in flux. The priority for our 2009
organic spending is to spend within our internally generated cash flow in order
to preserve our liquidity and retain flexibility. We expect our
capital spending level to be significantly reduced compared to our preliminary
budget. At this time, we intend to curtail our organic drilling
programs, while testing several new play concepts, notably in the Bakken Shale
in the Alberta Basin and the Eagle Ford Shale in South Texas. We have the
discretion to adjust capital spending plans throughout the year in response to
market conditions and the availability of proceeds from possible
divestitures. These adjustments could include shutting down our core
area drilling programs until such time as services costs contract and/or
commodity prices recover. We will actively monitor our spending
throughout the year. Our goal is to be financially prudent; however,
our capital decisions could significantly impact targets and
performance. Given the uncertainty in our capital program, it is not
practical to provide production guidance at the outset of
2009. However, it is likely that, at current prices, our capital
spending level would not be sufficient to grow production or reserves
organically.
We
recognize that we are operating in one of the most challenging business
environments in recent history and that the credit crisis, declining oil prices,
lower natural gas prices and a weakening global economic outlook are all
adversely impacting the business environment. We are working with our
lenders to effectively stay abreast of market and creditor conditions to ensure
prudent and timely decisions should market conditions deteriorate
further. We believe that we have sufficient liquidity and operational
flexibility to fund and actively manage a prudent capital expenditures program,
including, but not limited to, capping these expenditures in an annual period to
the cash flows available from operating activities. We may also
undertake divestitures to generate cash and exit non-core areas. Also
of note, our capital expenditures are primarily in areas where Rosetta acts as
operator and has high working interests. As a result, we do not
believe we have significant exposure to joint interest partners who
may be unable to fund their portion of any capital program, but we are
monitoring partner situations in light of the current economic
environment. We are actively working with service companies and
suppliers to mitigate costs, and we are examining all cash costs for improved
efficiency.
To the
extent that capital expenditures or prudent acquisitions require cash flow in
excess of available funds, we would consider drawing on our unused capacity
under our existing revolving credit facility. As of December 31, 2008, the
undrawn credit available to us was $175.0 million. We have not
received any indication from our lenders that draws under the credit facility
are restricted below current availability at this time and we are proactively
communicating with them on a routine basis. We affirmed our borrowing base in
the third quarter of 2008 at $400.0 million and the next redetermination is to
begin in March 2009. Our plan is to extend the term of our revolving
credit facility in the first half of 2009.
Finally,
with respect to the current market environment for liquidity and access to
credit, the Company, through banks participating in its credit facility, has
invested available cash in money market accounts and funds whose
investments are limited to United States Government Securities, securities
backed by the United States Government, or securities of United States
Government agencies. The Company followed this policy prior to the recent
changes in credit markets, and believes this is an appropriate approach for the
investment of Company funds in the current environment.
All
counterparties to our derivative instruments are participants in our credit
facilities, and we have not received any indication that any of these
counterparties are unable to perform their required obligations under the terms
of the derivative contracts, although we are mindful that this could change and
we are staying alert for such changes. Similarly, we have not received any
indication that any of the banks participating in the existing bank facility are
not capable of performing their obligations under the terms of the credit
agreement.
Financial
Highlights
Our
consolidated financial statements reflect total revenue of $499.3 million on
total volumes of 53.6 Bcfe for the year ended December 31,
2008. Operating loss was $275.3 million, or (55%) of total revenue,
and included depreciation, depletion and amortization expense of $198.9 million,
a non-cash, pre-tax full cost ceiling test impairment charge of $444.4 million,
lease operating expense of $55.7 million and $7.2 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 and $12.4 million of litigation expense related to the Calpine
Settlement, offset by interest income on short-term cash
investments.
Critical
Accounting Policies and Estimates
The
discussion and analysis of our financial condition and results of operations are
based upon the Consolidated 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. 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. Financial Statements and Supplementary
Data, Note 2 - Summary of Significant Accounting Policies, for a discussion of
additional accounting policies and estimates made by management.
Principles of
Consolidation
The
accompanying consolidated financial statements as of December 31, 2008, 2007 and
2006, contain the accounts of the Company and its majority owned subsidiaries
after eliminating all significant intercompany balances and
transactions.
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 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, 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 & Associates, Inc. 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 consolidated balance sheet and the depreciation,
depletion and amortization amounts in the consolidated statement of
operations. For more information regarding reserve estimation,
including historical reserve revisions, refer to Item 8. Financial
Statements and Supplementary Data, Supplemental Oil and
Gas Disclosures.
Full
Cost Ceiling Limitation
Under the
full cost method, we are subject to quarterly calculations of a “ceiling” or
limitation on the amount of costs associated with our oil and gas properties
that can be capitalized on our balance sheet. This ceiling limits
such capitalized costs to the present value of estimated future cash flows from
proved oil and natural gas reserves (including the effect of any related hedging
activities) reduced by future operating expenses, development expenditures,
abandonment costs (net of salvage values) to the extent not included in oil and
gas properties pursuant to SFAS No. 143, and estimated future income taxes
thereon. If net capitalized costs exceed the applicable cost center
ceiling, we are subject to a ceiling test write-down to the extent of such
excess. If required, it would reduce earnings and stockholders’ equity in the
period of occurrence and result in lower DD&A 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. 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
but prior to the issuance of our financial statements in which a write-down
might otherwise be required. The full cost ceiling test impairment calculations
also take into consideration the effects of hedging contracts that are
designated for hedge accounting. Given the fluctuation of natural gas and oil
prices, it is reasonably possible that the estimated discounted future net cash
flows from our proved reserves will change in the near term. If natural gas and
oil prices decline, or if we have downward revisions to our estimated proved
reserves, it is possible that write-downs of our oil and gas properties could
occur in the future.
Our
ceiling test computation was calculated quarterly using hedge adjusted market
prices based on Henry Hub gas prices and West Texas Intermediate oil
prices. At September 30, 2008, the ceiling test computation was based
on a Henry Hub price of $7.12 per MMBtu and a West Texas Intermediate oil price
of $96.37 per Bbl (adjusted for basis and quality differentials). At
December 31, 2008, the ceiling test computation was based on a Henry Hub price
of $5.71 per MMBtu and a West Texas Intermediate oil price of $41.00 per Bbl
(adjusted for basis and quality differentials). The use of these prices resulted
in non-cash, pre-tax writedowns of $205.7 million and $238.7 million at
September 30, 2008 and December 31, 2008, respectively. Due to the
volatility of commodity prices, should natural gas prices continue to decline in
the future, it is possible that an additional write-down could
occur.
There
were no ceiling test write-downs for the years ended December 31, 2007 and
2006.
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 $0.14 to $0.16 per MMcfe. This
estimated impact is based on current data at December 31, 2008 and actual events
could require different adjustments to DD&A.
Costs Withheld From
Amortization
Costs
associated with unevaluated properties are excluded from our amortization base
until we have evaluated the properties. The costs associated with unevaluated
leasehold acreage wells, currently drilling and capitalized interest are
initially excluded from our amortization base. Leasehold costs are either
transferred to our amortization base with the costs of drilling a well on the
lease or are assessed quarterly for possible impairment or reduction in
value. In addition, a portion of incurred (if not previously included
in the amortization base) and future estimated development costs associated with
qualifying major development projects may be temporarily excluded from
amortization. To qualify, a project must require significant costs to ascertain
the quantities of proved reserves attributable to the properties under
development (e.g., the installation of an offshore production platform from
which development wells are to be drilled). Incurred and estimated future
development costs are allocated between completed and future work. Any
temporarily excluded costs are included in the amortization base upon the
earlier of when the associated reserves are determined to be proved or
impairment is indicated.
Our
decision to withhold costs from amortization and the timing of the transfer of
those costs into the amortization base involve a significant amount of judgment
and may be subject to changes over time based on several factors, including our
drilling plans, availability of capital, project economics and results of
drilling on adjacent acreage. At December 31, 2008, our domestic full cost
pool had approximately $50.3 million of costs excluded from the amortization
base.
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 Statement of Financial
Accounting Standards (“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.
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
portion of our expected natural gas production through 2010. As of
December 31, 2008, 37% and 4% of our natural gas production was hedged using
swaps and costless collars, respectively, with settlement in 2009 and 9% of our
natural gas production was hedged with swaps for settlement in 2010, based on
our annual reserve report. 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 and 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) in the Consolidated Statement of Operations.
Fair
Value Measurements
In
September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS
No. 157, “Fair Value Measurements” (“SFAS No. 157”). SFAS No. 157
defines fair value, establishes a framework for measuring fair value and expands
the related disclosure requirements. SFAS No. 157 does not require
any new fair value measurements but may require some entities to change their
measurement practices. 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 also issued FASB Staff Position
(“FSP”) FAS 157-2 (“FSP No. 157-2”), which delayed the effective date of SFAS
No. 157 for nonfinancial assets and liabilities, except for items that are
recognized or disclosed at fair value in the financial statements on a recurring
basis (at least annually), until fiscal years beginning after November 15,
2008. Effective January 1, 2008, the Company partially adopted SFAS
No. 157 and has chosen to defer the implementation of SFAS No.157 for
nonfinancial assets and liabilities in accordance with FSP No. 157-2.
Accordingly, the Company will apply SFAS No. 157 to its nonfinancial assets and
liabilities that are disclosed or recognized at fair value on a nonrecurring
basis and other assets and liabilities in the first quarter of
2009. We are still in the process of evaluating the effect of SFAS
No. 157 on our nonfinancial assets and liabilities and therefore have not yet
determined the impact that it will have on our financial statements upon full
adoption in 2009. Nonfinancial assets and liabilities for which we have not yet
applied the provisions of SFAS No. 157 include our asset retirement
obligations. The adoption of SFAS No. 157 for financial assets and
liabilities did not have a significant effect on our consolidated financial
position, results of operations or cash flows. See Item 8. Financial
Statements and Supplementary Data, Note 7 - Fair Value
Measurements.
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.
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 our oil and gas properties. It is more likely
than not that we will realize this deferred tax asset in future years and
therefore, we have not recorded a valuation allowance as of December 31,
2008. See 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 (benefit) by approximately $3.0 million for the year ended
December 31, 2008.
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
The
following recently issued accounting developments may impact the Company in
future periods.
Business
Combinations. In December 2007, the FASB issued SFAS No. 141(R),
“Business Combinations” (“SFAS No. 141R”). SFAS No. 141R broadens the
guidance of SFAS No. 141, extending its applicability to all transactions and
other events in which one entity obtains control over one or more other
businesses. It broadens the fair value measurement and recognition of
assets acquired, liabilities assumed, and interests transferred as a result of
business combinations and requires that acquisition-related costs incurred prior
to the acquisition be expensed. SFAS No. 141R also expands the
definition of what qualifies as a business, and this expanded definition could
include prospective oil and gas purchases. This could cause us to
expense transaction costs for future oil and gas property purchases that we have
historically capitalized. Additionally, SFAS No. 141R expands the
required disclosures to improve the statement users’ abilities to evaluate the
nature and financial effects of business combinations. SFAS No. 141R
is effective for business combinations for which the acquisition date is on or
after January 1, 2009.
Noncontrolling Interests in
Consolidated Financial Statements. In December 2007, the
FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No.
160”), which improves the relevance, comparability and transparency of the
financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years beginning
after December 15, 2008. We do 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.
Disclosures about Derivative
Instruments and Hedging Activities. In March 2008, the
FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which
is intended to improve financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures. This statement
is effective for fiscal years beginning after November 15, 2008. We
do not expect the adoption of SFAS No. 161 to have a material impact on the
Company's consolidated financial position, results of operations or cash
flows.
Fair Value
Measurements. In October 2008, the FASB issued FSP FAS 157-3,
“Determining the Fair Value of a Financial Asset When the Market for That Asset
Is Not Active” (“FSP FAS 157-3”). This FSP clarifies the application of
SFAS No. 157 in a market that is not active and provides an example to
illustrate key considerations in determining the fair value of a financial asset
when the market for that financial asset is not active. This FSP was
effective upon issuance, including prior periods for which financial statements
have not been issued. We applied this FSP to financial assets measured at
fair value on a recurring basis at September 30, 2008. See Item 8.
Financial Statements and Supplementary Data, Note 7 - Fair Value Measurements.
The adoption of FSP FAS 157-3 did not have a significant impact on our
consolidated financial position, results of operations or cash
flows.
Oil and Gas Reporting
Requirements. In December 2008, the SEC released Release No.
33-8995, “Modernization of Oil and Gas Reporting” (the
“Release”). The disclosure requirements under this Release will
permit reporting of oil and gas reserves using an average price based upon the
prior 12-month period rather than year-end prices and the use of new
technologies to determine proved reserves if those technologies have been
demonstrated to result in reliable conclusions about reserves
volumes. Companies will also be allowed to disclose probable and
possible reserves in SEC filings. In addition, companies will be
required to report the independence and qualifications of its reserves preparer
or auditor and file reports when a third party is relied upon to prepare
reserves estimates or conduct a reserves audit. The new disclosure
requirements become effective for the Company beginning with our annual report
on Form 10-K for the year ended December 31, 2009. We are currently
evaluating the impact of this Release on our oil and gas accounting
disclosures.
Results
of Operations
The
following table summarizes our results of operations and compares the year ended
December 31, 2008 to the years ended December 31, 2007 and 2006.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands, except per unit amounts)
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas sales
|
|
$ |
443,611 |
|
|
$ |
323,341 |
|
|
$ |
236,496 |
|
Oil
sales
|
|
$ |
55,736 |
|
|
$ |
40,148 |
|
|
$ |
35,267 |
|
Total
revenues
|
|
$ |
499,347 |
|
|
$ |
363,489 |
|
|
$ |
271,763 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production:
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas
(Bcf)
|
|
|
50.4 |
|
|
|
42.5 |
|
|
|
30.3 |
|
Oil
(MBbls)
|
|
|
546.4 |
|
|
|
561.2 |
|
|
|
551.3 |
|
Total
Equivalents (Bcfe)
|
|
|
53.6 |
|
|
|
45.8 |
|
|
|
33.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
Gas Price per Mcf
|
|
$ |
8.80 |
|
|
$ |
7.61 |
|
|
$ |
7.81 |
|
Avg.
Gas Price per Mcf excluding Hedging
|
|
|
9.17 |
|
|
|
7.07 |
|
|
|
6.83 |
|
Avg.
Oil Price per Bbl
|
|
|
102.00 |
|
|
|
71.54 |
|
|
|
64.01 |
|
Avg.
Revenue per Mcfe
|
|
$ |
9.32 |
|
|
$ |
7.94 |
|
|
$ |
8.14 |
|
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, 2008 Compared to the Year Ended December 31,
2007
Total
revenue for the year ended December 31, 2008 was $499.3 million which is an
increase of $135.9 million, or 37%, from the year ended December 31,
2007. Approximately 89% of revenue was attributable to natural gas
sales on total volumes of 53.6 Bcfe.
Natural
Gas. For the year
ended December 31, 2008, natural gas revenue increased by 37% or $120.3 million,
including the realized impact of derivative instruments, from the comparable
period in 2007, to $443.6 million. The increase is primarily
attributable to increased volumes and favorable average realized prices in
2008. Production volumes increased overall by 19%, or 7.9 Bcfe,
primarily due to the increase in the number of productive wells during
2008. Net productive wells increased from 606 in 2007 to 825 in
2008. The effect of gas hedging activities on natural gas revenue for
the year ended December 31, 2008 was a loss of $18.7 million or a decrease of
$0.37 per Mcf as compared to a gain of $22.9 million or an increase of $0.54 per
Mcf for the year ended December 31, 2007. The average realized
natural gas price including the effects of hedging increased 16% or $1.19 to
$8.80 per Mcf for the year ended December 31, 2008 as compared to the same
period in 2007 of $7.61 per Mcf. In 2008, the Henry Hub natural gas spot price
averaged $9.13 per Mcf compared to the 2007 average of $7.17 per
Mcf.
Crude
Oil. For the year
ended December 31, 2008, oil revenue increased by 39% or $15.6 million primarily
due to the increase of $30.46 per Bbl in the average oil price from $71.54 per
Bbl for the year ended December 31, 2007 as compared to $102.00 per Bbl for the
year ended December 31, 2008. At December 31, 2008, the West Texas
Intermediate price for oil was $41.00 per Bbl compared to $92.50 per Bbl at
December 31, 2007. Oil volumes decreased by 3% or 14.8 MBbls to 546.4 MBbls at
December 31, 2008 from 561.2 MBbls at December 31, 2007. The decrease
in oil production volumes was associated with decreased production in the Gulf
of Mexico primarily due to the effects of Hurricane Ike in September 2008 as
well as lower production in Other Onshore.
Year
Ended December 31, 2007 Compared to the Year Ended December 31,
2006
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 37% or $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. In addition,
production volumes increased overall by 40% or 12.2 Bcfe. 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 or an increase of $0.54 per Mcf 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 3% 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 14% or $4.9 million primarily
due to the increase of $7.53 per Bbl in the average oil price from $64.01 per
Bbl for the year ended December 31, 2006 as compared to $71.54 per Bbl for the
year ended December 31, 2007. Oil volumes increased by 2% or 9.9
MBbls to 561.2 MBbls at 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
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 per Mcf 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.
Operating
Expenses
The
following table presents information about our operating expenses:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands, except per unit amounts)
|
|
Lease
operating expense
|
|
$ |
55,694 |
|
|
$ |
47,044 |
|
|
$ |
36,273 |
|
Depreciation,
depletion and amortization
|
|
|
198,862 |
|
|
|
152,882 |
|
|
|
105,886 |
|
Impairment
of oil and gas properties
|
|
|
444,369 |
|
|
|
- |
|
|
|
- |
|
Production
taxes
|
|
|
13,528 |
|
|
|
6,417 |
|
|
|
6,433 |
|
General
and administrative costs
|
|
$ |
52,846 |
|
|
$ |
43,867 |
|
|
$ |
33,233 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$
per unit:
|
|
|
|
|
|
|
|
|
|
|
|
|
Avg.
lease operating expense per Mcfe
|
|
$ |
1.04 |
|
|
$ |
1.03 |
|
|
$ |
1.09 |
|
Avg.
DD&A per Mcfe
|
|
|
3.71 |
|
|
|
3.34 |
|
|
|
3.17 |
|
Avg.
production taxes per Mcfe
|
|
|
0.25 |
|
|
|
0.14 |
|
|
|
0.19 |
|
Avg.
G&A per Mcfe
|
|
$ |
0.99 |
|
|
$ |
0.96 |
|
|
$ |
1.00 |
|
Year
Ended December 31, 2008 Compared to the Year Ended December 31,
2007
Lease Operating
Expense. Lease operating expense increased $8.7 million for
the year ended December 31, 2008 as compared to the same period for 2007. This
overall increase is primarily due to the increase in the number of productive
wells as well as increased production of 17% for 2008 which led to higher costs
for equipment rentals, maintenance and repairs, and costs associated with
non-operated properties. Lease operating expense includes workover
costs of $0.14 per Mcfe, ad valorem taxes of $0.21 per Mcfe and insurance of
$0.03 per Mcfe for the year ended December 31, 2008 as compared to workover
costs of $0.11 per Mcfe, ad valorem taxes of $0.26 per Mcfe and insurance of
$0.05 per Mcfe for the same period in 2007.
Depreciation, Depletion, and
Amortization. Depreciation, depletion and amortization expense
increased $46.0 million for the year ended December 31, 2008 as compared to the
same period for 2007. The increase is due to a 17% increase in total
production and a higher DD&A rate for 2008 due to the decrease in oil and
natural gas reserves as compared to 2007. The DD&A rate for the
respective period in 2008 was $3.71 per Mcfe while the rate for the same period
in 2007 was $3.34 per Mcfe due to the increase in finding costs. Our
DD&A rate for the first quarter of 2009 is expected to be $3.03 per Mcfe
after the effects of the full cost ceiling write-down.
Impairment of Oil and Gas
Properties. Based upon the quarterly ceiling test computations
using hedge adjusted market prices in effect at September 30, 2008 and December
31, 2008, and in conjunction with the downward revisions of a portion of the
Company’s reserves in the third and fourth quarters of 2008, the net capitalized
costs of oil and natural gas properties exceeded the cost center ceiling at
September 30 and December 31, 2008 and a pre-tax, non-cash impairment expense of
$444.4 million was recorded.
Production
Taxes. Production taxes as a percentage of oil and natural gas
sales were 2.7% for the year ended December 31, 2008 as compared to 1.8% for the
year ended December 31, 2007. This increase is the result of
increased production in areas that do not qualify for tax credits for the year
ended December 31, 2008 as compared to the same period for
2007.
General and Administrative
Costs. General and administrative costs, net of capitalized
general and administrative costs of $7.1 million for the year ended December 31,
2008, increased by $9.0 million for the year ended December 31, 2008 as compared
to the same period for 2007, with capitalized general and administrative costs
of $5.5 million. The increase in costs incurred in the current period
are primarily related to increases in legal fees related to the Calpine
litigation of $6.9 million and increases in payroll expenses of $2.1
million resulting from increased headcount and a $1.3 million accrual related to
the severance of a former executive officer, as well as the absence of
approximately $5.0 million in CEO transition costs that were incurred in 2007
but not 2008.
Year
Ended December 31, 2007 Compared to the Year Ended December 31,
2006
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
per Mcfe 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 2007 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
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.
Total
Other Expense
Other
expense includes interest expense, interest income and other income/expense, net
which increased $10.2 million for the year ended December 31, 2008 as compared
to the respective period in 2007. The increase in other expense is
the result of a $12.4 million charge related to the Calpine Settlement partially
offset by $3.0 million decrease in interest expense in 2008.
Other
expense increased $2.5 million for the year ended December 31, 2007 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. We expended $35.3
million during the fourth quarter of 2006 to fund various asset acquisitions and
$38.7 million during the second quarter of 2007 for the acquisition of the OPEX
Properties.
Other
expense for the year ended December 31, 2006 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.
Provision
for Income Taxes
Our 2008
income tax benefit of $112.8 million was primarily due to the 2008 ceiling test
write-downs. For the year ended December 31, 2008, the effective tax rate
was 37.5% compared to the effective tax rate of 37.3% for the year ended
December 31, 2007 and 38.3% for the year ended December 31, 2006. 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 a portion 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. The effects of these derivative
transactions on our natural gas sales are discussed above under “Results of
Operations – Natural Gas.” The majority of our capital expenditures
are discretionary and could be curtailed if our cash flows decline from expected
levels. Current economic conditions and lower commodity prices could
adversely affect our cash flow and liquidity. We will continue to monitor our
cash flow and liquidity and if appropriate, we may consider adjusting our
capital expenditure program.
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 and expires on April 5, 2010.
Availability under the Revolver is restricted to the borrowing
base. 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 June 2008, the borrowing base was
adjusted to $400.0 million and affirmed in December 2008. The next
borrowing base review is scheduled to begin on March 2, 2009. 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%.
These rates over LIBOR were adjusted in June 2008 to be 1.125% to
1.875%. 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 membership interests 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. At December 31, 2008,
the Company’s current ratio was 2.7 and the leverage ratio was
0.8. 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,
2008. As of December 31, 2008, the Company had $175.0 million
available for borrowing under their revolving line of credit. All amounts drawn
under the Revolver are due and payable on April 5, 2010.
Second Lien Term Loan.
BNP Paribas, in July 2005, also provided the Company
with a second lien term loan concurrent with the Acquisition of oil and gas
properties from Calpine (“Term Loan”). Borrowings under the Term Loan
are $75.0 million as of December 31, 2008. Such borrowings are
syndicated to a group of lenders including BNP Paribas. Borrowings
under the Term Loan bear interest at LIBOR plus 4.00%. 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. At December 31, 2008, the
Company’s asset coverage ratio was 3.1 and the leverage ratio was
0.8. 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, 2008. 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 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
Revolver maturing on April 5, 2010. We are in discussion with the
lenders under our Revolver to extend the maturity of the Revolver and
the Term Loan. If we are unable to extend the maturity of the
Revolver, it will become a current liability on April 5, 2009 and would result
in Rosetta being in default with respect to the working capital covenants in the
revolving credit facility and second lien term loan. Similarly, if we are unable
to extend the maturity of the Term Loan, it will become a current liability on
July 7, 2009. We believe that we will be successful in extending
these maturities on acceptable terms and conditions. Current market conditions
are expected to result in increased costs of borrowing.
Working
Capital
At
December 31, 2008, we had a working capital surplus of $28.6 million as compared
to a working capital deficit of $62.9 million at December 31,
2007. 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 surplus was largely caused by the
increases in our cash balance and short-term hedged assets in conjunction with a
decrease in our accounts payable and other current liabilities
balances. As of December 31, 2008, the working capital asset balances
of our cash and cash equivalents and derivative instruments were approximately
$42.9 million and $34.7 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 $48.8
million as of December 31, 2008.
Cash
Flows
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Cash
flows provided by operating activities
|
|
$ |
374,719 |
|
|
$ |
257,307 |
|
|
$ |
199,610 |
|
Cash
flows used in investing activities
|
|
|
(393,070 |
) |
|
|
(322,041 |
) |
|
|
(236,064 |
) |
Cash
flows provided by (used in) financing activities
|
|
|
57,990 |
|
|
|
5,170 |
|
|
|
(490 |
) |
Net
increase (decrease) in cash and cash equivalents
|
|
$ |
39,639 |
|
|
$ |
(59,564 |
) |
|
$ |
(36,944 |
) |
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,
2008.
Cash
flows provided by operating activities increased by $117.4 million for the year
ended December 31, 2008 as compared to the same period for 2007. This increase
is largely due to higher natural gas and oil prices during 2008 compared to
2007. As noted above, we also had a working capital surplus of $28.6
million, which was largely caused by the increase in our cash
balance. For the year ended December 31, 2008, we incurred
approximately $334.4 million in capital expenditures as compared to $336.1
million for the year ended December 31, 2007. For the year ended
December 31, 2008, we had net losses of $188.1 million with an increase of
production of 17% as compared to the year ended December 31, 2007 with net
income of $57.2 million.
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, oil and gas properties impairments,
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.
Investing
Activities. The primary driver of cash used in investing
activities is capital spending.
Cash
flows used in investing activities increased by $71.0 million for the year ended
December 31, 2008 as compared to the same period for 2007 and related to our
expenditures for the acquisitions and development of oil and gas properties and
drilling. The Company acquired the Petroflow properties in the San
Juan Basin for $29.0 million, the Pinedale and South Texas properties for
approximately $55.0 million, and the Calpine non-consent properties as part of
the Calpine Settlement for $30.9 million. Additionally, acquisition
costs for the year ended December 31, 2008 include a non-cash purchase price
adjustment of $36.7 million related to the release of suspended revenues and
non-consent liabilities associated with non-consent properties as part of the
Calpine Settlement, as well as an $8.0 million reduction in accrued capital
costs. During the year ended December 31, 2008, we participated in
the drilling of 184 gross wells as compared to the drilling of 195 gross wells
for the year ended December 31, 2007.
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.
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 $52.8 million for the year
ended December 31, 2008 as compared to the same period for 2007. The
net increase is primarily related to net borrowings of $55 million made in 2008
against the Revolver. In addition, there was an increase of
approximately $3.0 million in the stock options exercised for the year ended
December 31, 2008 compared to 2007.
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.
Commodity
Price Risk, Interest Rate Risk 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 hedges 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 these activities 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 portion of our expected
natural gas production through 2010. 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.
The
following table sets forth the results of commodity hedging transaction
settlements for the year ended December 31, 2008:
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
Natural
Gas
|
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
26,684,616 |
|
|
|
23,464,500 |
|
Increase
(decrease) in natural gas sales revenue (In thousands)
|
|
$ |
(18,669 |
) |
|
$ |
22,926 |
|
Interest
Rate Swaps
|
|
|
|
|
|
|
|
|
Decrease
(increase) in interest expense (In thousands)
|
|
$ |
(1,158 |
) |
|
$ |
20 |
|
Borrowings
under our Revolver and Term Loan mature on April 5, 2010 and July 7, 2010,
respectively, and bear interest at a LIBOR-based rate. This exposes us to risk
of earnings loss due to increases in market interest rates. To mitigate this
exposure, we have entered into a series of interest rate swap agreements through
June 2009. 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.
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,
2008, 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, 2008 were $334.4 million,
and we have plans to carefully execute an organic capital program in 2009 that
can be funded from internally generated cash flows. We also have the
discretion to use available cash, borrowing base, and proceeds from divestitures
to fund capital expenditures, including acquisitions, that make sense for
Rosetta. However, our main priority is to preserve
liquidity.
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, 2008, the aggregate amounts of our contractually obligated
payment commitments for the next five years are as follows:
|
|
Payments
Due By Period
|
|
|
|
Total
|
|
|
2009
|
|
|
2010
to 2011
|
|
|
2012
to 2013
|
|
|
2014
& Beyond
|
|
|
(In
thousands)
|
|
Senior
secured revolving line of credit
|
|
$ |
225,000 |
|
|
$ |
- |
|
|
$ |
225,000 |
|
|
$ |
- |
|
|
$ |
- |
|
Second
lien term loan
|
|
|
75,000 |
|
|
|
- |
|
|
|
75,000 |
|
|
|
- |
|
|
|
- |
|
Operating
leases
|
|
|
15,793 |
|
|
|
3,055 |
|
|
|
6,021 |
|
|
|
6,204 |
|
|
|
513 |
|
Interest
payments on long-term debt (1)
|
|
|
10,494 |
|
|
|
7,638 |
|
|
|
2,856 |
|
|
|
- |
|
|
|
- |
|
Rig
commitments
|
|
|
5,025 |
|
|
|
5,025 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Total
contractual obligations
|
|
$ |
331,312 |
|
|
$ |
15,718 |
|
|
$ |
308,877 |
|
|
$ |
6,204 |
|
|
$ |
513 |
|
___________________________________
(1)
Future interest payments were calculated based on interest rates and amounts
outstanding at December 31, 2008.
Asset Retirement Obligation.
The Company also has liabilities of $27.9 million related to asset retirement
obligations on its Consolidated Balance Sheet at December 31, 2008 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. Financial Statements and Supplementary Data, Note 9 - Asset Retirement
Obligation.
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.
Off-Balance
Sheet Arrangements
At
December 31, 2008 and 2007, we did not have any off-balance sheet
arrangements.
Forward-Looking
Statements
This
report includes forward-looking information regarding Rosetta that is intended
to be covered by the “forward-looking statements” within the meaning of the
Private Securities Litigation Reform Act of 1995, 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 Part I. of 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:
–
|
conditions in
the energy and economic markets;
|
–
|
the
supply and demand for natural gas and
oil;
|
–
|
the price of
natural gas and oil;
|
–
|
potential
reserve revisions;
|
–
|
changes
or advances in technology;
|
–
|
the
availability and cost of relevant raw materials, goods and
services;
|
–
|
future
processing volumes and pipeline
throughput;
|
–
|
the
occurrence of property acquisitions or
divestitures;
|
–
|
drilling
and exploration risks;
|
–
|
the
availability and cost of processing and
transportation;
|
–
|
developments
in oil-producing and natural gas-producing
countries;
|
–
|
competition
in the oil and natural gas
industry;
|
–
|
the
ability and willingness of our current or potential counterparties or
vendors to enter into transactions with us and/or to fulfill their
obligations to us;
|
–
|
our
ability to access the capital markets on favorable terms or at
all;
|
–
|
our
ability to obtain credit and/or capital in desired amounts and/or on
favorable terms;
|
–
|
failure
of our joint interest partners to fund any or all of their portion of any
capital program;
|
–
|
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;
|
–
|
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. See Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations “ Commodity Price
Risk, Interest Rate Risk and Related Hedging Activities.”
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.
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.
We use
derivative transactions to manage exposure to changes in commodity prices and
interest rates. Our objective for holding derivative instruments is 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.
On
December 31, 2008, we had open natural gas derivative hedges in an asset
position with a fair value of $39.4 million. A 10 percent increase in
natural gas prices would reduce the fair value by approximately $15.1 million,
while a 10 percent decrease in natural gas prices would increase the fair value
by approximately $14.7 million. These fair value changes assume
volatility based on prevailing market parameters at December 31,
2008.
As of
December 31, 2008, we had the following financial fixed price swap
positions outstanding with average underlying prices that represent hedged
prices of commodities at various market locations:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
|
Total
of Notional Volume
MMBtu
|
|
|
Average
Floor/Fixed Prices
MMBtu
|
|
|
Average
Ceiling Prices MMBtu
|
|
|
Natural
Gas Production Hedged (1)
|
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2009
|
Swap
|
Cash
flow
|
|
|
52,141 |
|
|
|
19,031,465 |
|
|
$ |
7.65 |
|
|
$ |
- |
|
|
|
37 |
% |
|
$ |
31,082 |
|
2009
|
Costless
Collar
|
Cash
flow
|
|
|
5,000 |
|
|
|
1,825,000 |
|
|
|
8.00 |
|
|
|
10.05 |
|
|
|
4 |
% |
|
|
3,660 |
|
2010
|
Swap
|
Cash
flow
|
|
|
10,000 |
|
|
|
3,650,000 |
|
|
|
8.31 |
|
|
|
- |
|
|
|
9 |
% |
|
|
4,615 |
|
|
|
|
|
|
|
|
|
|
24,506,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
39,357 |
|
|
(1)
|
Estimated
based on anticipated future gas
production.
|
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 $400
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 1.125% to 1.875%, based on
facility utilization. The Revolver will mature on April 5, 2010.
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 $175.0 million as of December 31, 2008.
A one hundred basis point increase in each of the LIBOR rate and federal funds
rate as of December 31, 2008 and 2007 for both our Revolver and Term Loan would
result in an estimated $3.0 million and $2.5 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 $50.0 million of our variable rate debt through
June 2009. As of December 31, 2008 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)
|
|
2009
|
Swap
|
Cash
flow
|
|
|
4.55 |
% |
|
$ |
(985 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(985 |
) |
Item 8. Financial Statements and Supplementary
Data
Index
to Financial Statements
|
|
|
Report
of Independent Registered Public Accounting Firm
|
|
|
Consolidated
Balance Sheet at December 31, 2008 and 2007
|
|
|
Consolidated
Statement of Operations for the years ended December 31, 2008, 2007 and
2006
|
|
|
Consolidated
Statement of Cash Flows for the years ended December 31, 2008, 2007 and
2006
|
|
|
Consolidated
Statement of Stockholders' Equity for the years ended December 31, 2008,
2007 and 2006
|
|
|
Notes
to Consolidated Financial Statements
|
|
|
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
present fairly, in all material respects, the financial position of Rosetta
Resources Inc. and its subsidiaries (the "Company") at December 31, 2008 and
2007, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2008 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, 2008, 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 Annual 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 were integrated audits in 2008 and 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.
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
27, 2009
Houston,
Texas
Item
8. Financial Statements and Supplementary Data
Rosetta
Resources Inc.
Consolidated
Balance Sheet
(In
thousands, except share amounts)
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Assets
|
|
|
|
|
|
|
Current
assets:
|
|
|
|
|
|
|
Cash
and cash equivalents
|
|
$ |
42,855 |
|
|
$ |
3,216 |
|
Restricted
cash
|
|
|
1,421 |
|
|
|
- |
|
Accounts
receivable
|
|
|
41,885 |
|
|
|
55,048 |
|
Derivative
instruments
|
|
|
34,742 |
|
|
|
3,966 |
|
Prepaid
expenses
|
|
|
5,046 |
|
|
|
10,413 |
|
Other
current assets
|
|
|
4,071 |
|
|
|
4,249 |
|
Total
current assets
|
|
|
130,020 |
|
|
|
76,892 |
|
Oil
and natural gas properties, full cost method, of which $50.3 million at
December 31, 2008 and $40.9 million at December 31, 2007 were excluded
from amortization
|
|
|
1,900,672 |
|
|
|
1,566,082 |
|
Other
property and equipment
|
|
|
9,439 |
|
|
|
6,393 |
|
|
|
|
1,910,111 |
|
|
|
1,572,475 |
|
Accumulated
depreciation, depletion, and amortization, including
impairment
|
|
|
(935,851 |
) |
|
|
(295,749 |
) |
Total
property and equipment, net
|
|
|
974,260 |
|
|
|
1,276,726 |
|
Deferred
loan fees
|
|
|
1,168 |
|
|
|
2,195 |
|
Deferred
tax asset
|
|
|
42,652 |
|
|
|
- |
|
Other
assets
|
|
|
6,278 |
|
|
|
1,401 |
|
Total
other assets
|
|
|
50,098 |
|
|
|
3,596 |
|
Total
assets
|
|
$ |
1,154,378 |
|
|
$ |
1,357,214 |
|
|
|
|
|
|
|
|
|
|
Liabilities
and Stockholders' Equity
|
|
|
|
|
|
|
|
|
Current
liabilities:
|
|
|
|
|
|
|
|
|
Accounts
payable
|
|
$ |
2,268 |
|
|
$ |
33,949 |
|
Accrued
liabilities
|
|
|
48,824 |
|
|
|
64,216 |
|
Royalties
payable
|
|
|
17,388 |
|
|
|
18,486 |
|
Derivative
instruments
|
|
|
985 |
|
|
|
2,032 |
|
Prepayment
on gas sales
|
|
|
19,382 |
|
|
|
20,392 |
|
Deferred
income taxes
|
|
|
12,575 |
|
|
|
720 |
|
Total
current liabilities
|
|
|
101,422 |
|
|
|
139,795 |
|
Long-term
liabilities:
|
|
|
|
|
|
|
|
|
Derivative
instruments
|
|
|
- |
|
|
|
13,508 |
|
Long-term
debt
|
|
|
300,000 |
|
|
|
245,000 |
|
Asset
retirement obligation
|
|
|
26,584 |
|
|
|
18,040 |
|
Deferred
income taxes
|
|
|
- |
|
|
|
67,916 |
|
Total
liabilities
|
|
|
428,006 |
|
|
|
484,259 |
|
|
|
|
|
|
|
|
|
|
Commitments
and Contingencies (Note 11)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stockholders'
equity:
|
|
|
|
|
|
|
|
|
Preferred
stock, $0.001 par value; authorized 5,000,000 shares; no shares issued in
2008 or 2007
|
|
|
- |
|
|
|
- |
|
Common
stock, $0.001 par value; authorized 150,000,000 shares; issued 51,031,481
shares and 50,542,648 shares at December 31, 2008 and December 31, 2007,
respectively
|
|
|
51 |
|
|
|
50 |
|
Additional
paid-in capital
|
|
|
773,676 |
|
|
|
762,827 |
|
Treasury
stock, at cost; 155,790 shares and 109,303 shares at December 31, 2008 and
2007, respectively
|
|
|
(2,672 |
) |
|
|
(2,045 |
) |
Accumulated
other comprehensive income (loss)
|
|
|
24,079 |
|
|
|
(7,225 |
) |
Retained
earnings (accumulated deficit)
|
|
|
(68,762 |
) |
|
|
119,348 |
|
Total
stockholders' equity
|
|
|
726,372 |
|
|
|
872,955 |
|
Total
liabilities and stockholders' equity
|
|
$ |
1,154,378 |
|
|
$ |
1,357,214 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Operations
(In
thousands, except per share amounts)
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Revenues:
|
|
|
|
|
|
|
|
|
|
Natural
gas sales
|
|
$ |
443,611 |
|
|
$ |
323,341 |
|
|
$ |
236,496 |
|
Oil
sales
|
|
|
55,736 |
|
|
|
40,148 |
|
|
|
35,267 |
|
Total
revenues
|
|
|
499,347 |
|
|
|
363,489 |
|
|
|
271,763 |
|
Operating
costs and expenses:
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease
operating expense
|
|
|
55,694 |
|
|
|
47,044 |
|
|
|
36,273 |
|
Depreciation,
depletion, and amortization
|
|
|
198,862 |
|
|
|
152,882 |
|
|
|
105,886 |
|
Impairment
of oil and gas properties
|
|
|
444,369 |
|
|
|
- |
|
|
|
- |
|
Treating
and transportation
|
|
|
6,323 |
|
|
|
4,230 |
|
|
|
2,544 |
|
Marketing
fees
|
|
|
3,064 |
|
|
|
2,450 |
|
|
|
2,257 |
|
Production
taxes
|
|
|
13,528 |
|
|
|
6,417 |
|
|
|
6,433 |
|
General
and administrative costs
|
|
|
52,846 |
|
|
|
43,867 |
|
|
|
33,233 |
|
Total
operating costs and expenses
|
|
|
774,686 |
|
|
|
256,890 |
|
|
|
186,626 |
|
Operating
income (loss)
|
|
|
(275,339 |
) |
|
|
106,599 |
|
|
|
85,137 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
(income) expense
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest
expense, net of interest capitalized
|
|
|
14,688 |
|
|
|
17,734 |
|
|
|
17,428 |
|
Interest
income
|
|
|
(1,600 |
) |
|
|
(1,674 |
) |
|
|
(4,503 |
) |
Other
(income) expense, net
|
|
|
12,510 |
|
|
|
(698 |
) |
|
|
(40 |
) |
Total
other expense
|
|
|
25,598 |
|
|
|
15,362 |
|
|
|
12,885 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income
(loss) before provision for income taxes
|
|
|
(300,937 |
) |
|
|
91,237 |
|
|
|
72,252 |
|
Income
tax expense (benefit)
|
|
|
(112,827 |
) |
|
|
34,032 |
|
|
|
27,644 |
|
Net
income (loss)
|
|
$ |
(188,110 |
) |
|
$ |
57,205 |
|
|
$ |
44,608 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings
(loss) per share:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
$ |
(3.71 |
) |
|
$ |
1.14 |
|
|
$ |
0.89 |
|
Diluted
|
|
$ |
(3.71 |
) |
|
$ |
1.13 |
|
|
$ |
0.88 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted
average shares outstanding:
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic
|
|
|
50,693 |
|
|
|
50,379 |
|
|
|
50,237 |
|
Diluted
|
|
|
50,693 |
|
|
|
50,589 |
|
|
|
50,408 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Cash Flows
(In
thousands)
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Cash
flows from operating activities
|
|
|
|
|
|
|
|
|
|
Net
income (loss)
|
|
|
(188,110 |
) |
|
|
57,205 |
|
|
|
44,608 |
|
Adjustments
to reconcile net income to net cash from operating
activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation,
depletion and amortization
|
|
|
198,862 |
|
|
|
152,882 |
|
|
|
105,886 |
|
Impairment
of oil and gas properties
|
|
|
444,369 |
|
|
|
- |
|
|
|
- |
|
Deferred
income taxes
|
|
|
(116,519 |
) |
|
|
33,915 |
|
|
|
27,472 |
|
Amortization
of deferred loan fees recorded as interest expense
|
|
|
1,027 |
|
|
|
1,180 |
|
|
|
1,180 |
|
Stock
compensation expense
|
|
|
7,234 |
|
|
|
6,831 |
|
|
|
5,702 |
|
Other
non-cash items
|
|
|
(512 |
) |
|
|
(181 |
) |
|
|
(171 |
) |
Change
in operating assets and liabilities:
|
|
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable
|
|
|
13,163 |
|
|
|
(18,640 |
) |
|
|
3,643 |
|
Income
taxes receivable
|
|
|
(776 |
) |
|
|
- |
|
|
|
6,000 |
|
Prepaid
expenses
|
|
|
5,367 |
|
|
|
(1,652 |
) |
|
|
650 |
|
Other
current assets
|
|
|
178 |
|
|
|
(1,284 |
) |
|
|
(2,965 |
) |
Other
assets
|
|
|
191 |
|
|
|
144 |
|
|
|
1,691 |
|
Accounts
payable
|
|
|
5,031 |
|
|
|
10,909 |
|
|
|
8,765 |
|
Accrued
liabilities
|
|
|
7,322 |
|
|
|
3,998 |
|
|
|
310 |
|
Royalties
payable
|
|
|
(2,108 |
) |
|
|
12,000 |
|
|
|
(3,161 |
) |
Net
cash provided by operating activities
|
|
|
374,719 |
|
|
|
257,307 |
|
|
|
199,610 |
|
Cash
flows from investing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Acquisition
of oil and gas properties
|
|
|
(163,187 |
) |
|
|
(38,656 |
) |
|
|
(35,286 |
) |
Purchases
of oil and gas assets
|
|
|
(228,464 |
) |
|
|
(284,541 |
) |
|
|
(201,293 |
) |
Increase
in restricted cash
|
|
|
(1,421 |
) |
|
|
- |
|
|
|
- |
|
Other
|
|
|
2 |
|
|
|
1,156 |
|
|
|
515 |
|
Net
cash used in investing activities
|
|
|
(393,070 |
) |
|
|
(322,041 |
) |
|
|
(236,064 |
) |
Cash
flows from financing activities
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
offering transaction fees
|
|
|
- |
|
|
|
- |
|
|
|
268 |
|
Borrowings
on revolving credit facility
|
|
|
55,000 |
|
|
|
10,000 |
|
|
|
- |
|
Payments
on revolving credit facility
|
|
|
- |
|
|
|
(5,000 |
) |
|
|
- |
|
Proceeds
from stock options exercised
|
|
|
3,617 |
|
|
|
653 |
|
|
|
804 |
|
Purchases
of treasury stock
|
|
|
(627 |
) |
|
|
(483 |
) |
|
|
(1,562 |
) |
Net
cash provided by (used in) financing activities
|
|
|
57,990 |
|
|
|
5,170 |
|
|
|
(490 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
increase (decrease) in cash
|
|
|
39,639 |
|
|
|
(59,564 |
) |
|
|
(36,944 |
) |
Cash
and cash equivalents, beginning of year
|
|
|
3,216 |
|
|
|
62,780 |
|
|
|
99,724 |
|
Cash
and cash equivalents, end of year
|
|
$ |
42,855 |
|
|
$ |
3,216 |
|
|
$ |
62,780 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
paid for interest expense, net of capitalized interest
|
|
$ |
13,658 |
|
|
$ |
18,862 |
|
|
$ |
17,875 |
|
Cash
paid for income taxes
|
|
$ |
4,470 |
|
|
$ |
115 |
|
|
$ |
172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Supplemental
non-cash disclosures:
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures included in Accrued liabilities
|
|
$ |
26,555 |
|
|
$ |
34,599 |
|
|
$ |
21,674 |
|
Accrued
purchase price adjustment
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
11,400 |
|
Release
of suspended net revenues resulting from Calpine Settlement included in
Accounts payable and Acquisition of oil and gas properties
|
|
$ |
36,713 |
|
|
$ |
- |
|
|
$ |
- |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Consolidated
Statement of Stockholders’ Equity
(In
thousands, except share amounts)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated
|
|
|
Retained
|
|
|
|
|
|
|
Common
Stock
|
|
|
Additional
|
|
|
Treasury
Stock
|
|
|
Other
|
|
|
Earnings
/
|
|
|
Total
|
|
|
|
|
|
|
Paid-In
|
|
|
|
|
|
Comprehensive
|
|
|
(Accumulated
|
|
|
Stockholders'
|
|
|
|
Shares
|
|
|
Amount
|
|
|
Capital
|
|
|
Shares
|
|
|
Amount
|
|
|
(Loss)/Income
|
|
|
Deficit)
|
|
|
Equity
|
|
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
expense 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 |
|
Stock
options exercised
|
|
|
214,119 |
|
|
|
1 |
|
|
|
3,615 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
3,616 |
|
Treasury
stock - employee tax payment
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
46,487 |
|
|
|
(627 |
) |
|
|
- |
|
|
|
- |
|
|
|
(627 |
) |
Stock-based
compensation
|
|
|
- |
|
|
|
- |
|
|
|
7,234 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
7,234 |
|
Vesting
of restricted stock
|
|
|
274,714 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Comprehensive
Loss:
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Net
Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(188,110 |
) |
|
|
(188,110 |
) |
Change
in fair value of derivative hedging instruments
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
30,059 |
|
|
|
- |
|
|
|
30,057 |
|
Hedge
settlements reclassified to income
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
19,827 |
|
|
|
- |
|
|
|
19,829 |
|
Tax
expense related to cash flow hedges
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(18,582 |
) |
|
|
- |
|
|
|
(18,582 |
) |
Comprehensive
Loss
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
(156,806 |
) |
Balance
December 31, 2008
|
|
|
51,031,481 |
|
|
$ |
51 |
|
|
$ |
773,676 |
|
|
|
155,790 |
|
|
$ |
(2,672 |
) |
|
$ |
24,079 |
|
|
$ |
(68,762 |
) |
|
$ |
726,372 |
|
The
accompanying notes to the financial statements are an integral part
hereof.
Rosetta
Resources Inc.
Notes
to Consolidated Financial Statements
(1)
|
Organization
and Operations of the Company
|
Nature of
Operations. Rosetta Resources Inc. (together with its
consolidated subsidiaries, the “Company”) is an independent oil and gas company
that 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 Rockies, 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 current year classifications. These reclassifications have no
impact on net income (loss).
(2)
|
Summary
of Significant Accounting Policies
|
Principles
of Consolidation and Basis of Presentation
The
accompanying consolidated financial statements for the years ended December 31,
2008, 2007 and 2006 contain the accounts of Rosetta Resources Inc. and its
majority owned subsidiaries after eliminating all significant intercompany
balances and transactions.
Use
of Estimates in Preparation of Financial Statements
The
preparation of the consolidated 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,valuation of derivative
instruments, 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.
With
respect to the current market environment for liquidity and access to credit,
the Company, through banks participating in its credit facility, has invested
available cash in money market accounts and funds whose investments
are limited to United States Government Securities, securities backed by the
United States Government, or securities of United States Government agencies.
The Company followed this policy prior to the recent changes in credit markets,
and believes this is an appropriate approach for the investment of Company funds
in the current environment.
Restricted
Cash
Restricted
cash of $1.4 million as of December 31, 2008 consists of cash deposited by the
Company in an escrow account, which was created in conjunction with the South
Texas acquisitions for potential environmental remediation costs associated with
acquired properties.
Allowance
for Doubtful Accounts
The
Company regularly reviews all aged accounts receivables for collectability and
establishes an allowance as necessary for individual customer
balances.
Property,
Plant and Equipment, Net
The
Company follows the full cost method of accounting for oil and natural gas
properties. 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 reserves in the cost center in which they are
produced, subject to a limitation that the capitalized costs not exceed the
value of those reserves. In some cases, however, certain significant costs, such
as those associated with offshore U.S. operations, 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 $7.1 million and $5.5 million of
internal costs for the years ended December 31, 2008 and 2007,
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. This
ceiling limits such capitalized costs to the present value of estimated future
cash flows from proved oil and natural gas reserves (including the effect of any
related hedging activities) reduced by future operating expenses, development
expenditures, abandonment costs (net of salvage values) to the extent not
included in oil and gas properties pursuant to SFAS No. 143, and estimated
future income taxes thereon. However, in periods in
which a write-down is required, if oil and gas prices increase subsequent to the
end of a quarter but prior to the issuance of our financial statements, the
Company may not be subject to a write-down. 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 quarterly using hedge adjusted
market prices based on Henry Hub gas prices and West Texas Intermediate oil
prices. At September 30, 2008, the ceiling test computation was based
on a Henry Hub price of $7.12 per MMBtu and a West Texas Intermediate oil price
of $96.37 per Bbl (adjusted for basis and quality differentials). At
December 31, 2008, the ceiling test computation was based on a Henry Hub price
of $5.71 per MMBtu and a West Texas Intermediate oil price of $41.00 per Bbl
(adjusted for basis and quality differentials). Cash flow hedges of natural gas
production in place at September 30 and December 31, 2008 increased the
calculated ceiling value by approximately $37 million (pre-tax) and $47 million
(pre-tax), respectively. Based upon studies to date, and in coordination
with the Company's independent reserve engineers, the Company recognized
a downward revision of 64 Bcfe of proved reserves during the third
quarter of 2008. Based upon this analysis and the reserve revision, a
non-cash, pre-tax write-down of $205.7 million was recorded at September 30,
2008. Due to continued declines in oil and gas prices and a downward
revision of 8 Bcfe due to year-end commodity prices, at December 31, 2008,
capitalized costs of our proved oil and gas properties exceeded our ceiling,
resulting in a non-cash, pre-tax write-down of $238.7 million. Due to
the volatility of commodity prices, should natural gas prices continue to
decline in the future, it is possible that an additional write-down could
occur.
No
impairment charge was recorded for the years ended December 31, 2007 and
2006.
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, 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. The carrying amount reported in the consolidated
balance sheet at December 31, 2008 for long-term debt is $300 million. The
Company adjusted the fair value measurement of its long-term debt as of December
31, 2008, in accordance with SFAS No. 157 using a discounted cash flow technique
that incorporates a market interest yield curve with adjustments for duration,
optionality and risk profile. The Company has determined the fair
market value of its debt to be $275 million at December 31,
2008.
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 and
financial institutions, respectively.
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
accumulated 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 6 – Commodity Hedging Contracts and
Other Derivatives 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 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, 2008 or 2007.
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.
Any
excess tax benefit is recognized as a credit to additional paid in capital when
realized and is calculated as the amount by which the tax deduction we receive
exceeds the deferred tax asset associated with the recorded stock compensation
expense. We have approximately $0.2 million of related excess tax
benefits which will be recognized upon utilization of our net operating loss
carryforward. SFAS No. 123R requires the cash flows that result from
tax deductions in excess of the compensation expense to be recognized
as financing activities.
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, 2008 and 2007, 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, 2008 and 2007, 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 bases 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
The
following recently issued accounting developments may impact the Company in
future periods.
Business
Combinations. In December 2007, the FASB issued SFAS No. 141(R),
“Business Combinations” (“SFAS No. 141R”). SFAS No. 141R broadens the
guidance of SFAS No. 141, extending its applicability to all transactions and
other events in which one entity obtains control over one or more other
businesses. It broadens the fair value measurement and recognition of
assets acquired, liabilities assumed, and interests transferred as a result of
business combinations and requires that acquisition-related costs incurred prior
to the acquisition be expensed. SFAS No. 141R also expands the
definition of what qualifies as a business, and this expanded definition could
include prospective oil and gas purchases. This could cause us to
expense transaction costs for future oil and gas property purchases that we have
historically capitalized. Additionally, SFAS No. 141R expands the
required disclosures to improve the statement users’ abilities to evaluate the
nature and financial effects of business combinations. SFAS No. 141R
is effective for business combinations for which the acquisition date is on or
after January 1, 2009.
Noncontrolling Interests in
Consolidated Financial Statements. In December 2007, the
FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial
Statements, an amendment of Accounting Research Bulletin No. 51” (“SFAS No.
160”), which improves the relevance, comparability and transparency of the
financial information that a reporting entity provides in its consolidated
financial statements by establishing accounting and reporting standards for the
noncontrolling interest in a subsidiary and for the deconsolidation of a
subsidiary. This statement is effective for fiscal years beginning
after December 15, 2008. We do 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.
Disclosures about Derivative
Instruments and Hedging Activities. In March 2008, the
FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging
Activities – an Amendment of FASB Statement No. 133” (“SFAS No. 161”), which
is intended to improve financial reporting about derivative instruments and
hedging activities by requiring enhanced disclosures. This statement
is effective for fiscal years beginning after November 15,
2008. We do not
expect the adoption of SFAS No. 161 to have a material impact on the Company's
consolidated financial position, results of operations or cash
flows.
Fair Value
Measurements. In October 2008, the FASB issued FSP FAS 157-3,
“Determining the Fair Value of a Financial Asset When the Market for That Asset
Is Not Active” (“FSP FAS 157-3”). This FSP clarifies the application of
SFAS No. 157 in a market that is not active and provides an example to
illustrate key considerations in determining the fair value of a financial asset
when the market for that financial asset is not active. This FSP was
effective upon issuance, including prior periods for which financial statements
have not been issued. We applied this FSP to financial assets measured at
fair value on a recurring basis at September 30, 2008. See Note 7 - Fair
Value Measurements. The adoption of FSP FAS 157-3 did not have a
significant impact on our consolidated financial position, results of operations
or cash flows.
Oil and Gas Reporting
Requirements. In December 2008, the SEC released Release No.
33-8995, “Modernization of Oil and Gas Reporting” (the
“Release”). The disclosure requirements under this Release will
permit reporting of oil and gas reserves using an average price based upon the
prior 12-month period rather than year-end prices and the use of new
technologies to determine proved reserves if those technologies have been
demonstrated to result in reliable conclusions about reserves
volumes. Companies will also be allowed to disclose probable and
possible reserves in SEC filings. In addition, companies will be
required to report the independence and qualifications of its reserves preparer
or auditor and file reports when a third party is relied upon to prepare
reserves estimates or conduct a reserves audit. The new disclosure
requirements become effective for the Company beginning with our annual report
on Form 10-K for the year ended December 31, 2009. We are currently
evaluating the impact of this Release on our oil and gas accounting
disclosures.
Accounts
receivable consisted of the following:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Natural
gas, NGLs and oil revenue sales
|
|
$ |
37,982 |
|
|
$ |
46,376 |
|
Joint
interest billings
|
|
|
3,422 |
|
|
|
7,750 |
|
Short-term
receivable for royalty recoupment
|
|
|
481 |
|
|
|
922 |
|
Total
|
|
|
41,885 |
|
|
|
55,048 |
|
There are
no balances in accounts receivable that will not be collected and that an
allowance was unnecessary at December 31, 2008 and December 31,
2007.
(4)
|
Property,
Plant and Equipment
|
The
Company’s total property, plant and equipment consists of the
following:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,813,527 |
|
|
$ |
1,499,046 |
|
Unproved/unevaluated
properties
|
|
|
50,252 |
|
|
|
40,903 |
|
Gas
gathering system and compressor stations
|
|
|
36,893 |
|
|
|
26,133 |
|
Other
|
|
|
9,439 |
|
|
|
6,393 |
|
Total
|
|
|
1,910,111 |
|
|
|
1,572,475 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(935,851 |
) |
|
|
(295,749 |
) |
|
|
$ |
974,260 |
|
|
$ |
1,276,726 |
|
Included
in the Company’s oil and natural gas properties are asset retirement costs of
$23.2 million and $20.1 million at December 31, 2008 and 2007, respectively,
including additions of $1.7 million and $2.1 million for the year ended December
31, 2008 and 2007, respectively.
Pursuant
to full cost accounting rules, the Company must perform a ceiling test each
quarter on its proved oil and gas assets within each separate cost
center. The Company’s ceiling test was calculated using hedge
adjusted market prices of gas and oil at September 30 and December 31, 2008,
which were based on a Henry Hub price of $7.12 per MMBtu and $5.71 per MMBtu,
respectively, and a West Texas Intermediate oil price of $96.37 per Bbl and
$41.00 per Bbl (adjusted for basis and quality differentials), respectively.
Cash flow hedges of natural gas production in place at September 30 and December
31, 2008 increased the calculated ceiling value by approximately $37
million (pre-tax) and $47 million (pre-tax), respectively. Based upon
studies to date, and in coordination with the Company's independent reserve
engineers, the Company recognized a downward revision of 64 Bcfe of
proved reserves during the third quarter of 2008. Based upon this analysis
and the reserve revision, a non-cash, pre-tax write-down of $205.7 million was
recorded at September 30, 2008. Due to continued declines in oil and
gas prices and a downward revision of 8 Bcfe due to year-end commodity prices,
at December 31, 2008, capitalized costs of our proved oil and gas properties
exceeded our ceiling, resulting in a non-cash, pre-tax write-down of $238.7
million. It is possible that another write-down of the Company's oil
and gas properties could occur in the future should oil and natural gas
prices continue to decline and/or the Company experiences downward adjustments
to the estimated proved reserves.
Capitalized
costs excluded from depreciation, depletion, and amortization as of December 31,
2008 and 2007, are as follows by the year in which such costs were
incurred:
|
|
December
31, 2008
|
|
|
|
Total
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
Prior
|
|
|
|
(in
thousands)
|
|
Onshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
cost
|
|
|
13,320 |
|
|
|
13,320 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Exploration
cost
|
|
|
3,555 |
|
|
|
3,555 |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Acquisition
cost of undeveloped acreage
|
|
|
29,926 |
|
|
|
23,958 |
|
|
|
4,949 |
|
|
|
988 |
|
|
|
31 |
|
Capitalized
Interest
|
|
|
2,552 |
|
|
|
1,978 |
|
|
|
433 |
|
|
|
141 |
|
|
|
- |
|
|
|
|
49,353 |
|
|
|
42,811 |
|
|
|
5,382 |
|
|
|
1,129 |
|
|
|
31 |
|
Offshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
cost
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Exploration
cost
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Acquisition
cost of undeveloped acreage
|
|
|
786 |
|
|
|
- |
|
|
|
- |
|
|
|
786 |
|
|
|
- |
|
Capitalized
Interest
|
|
|
113 |
|
|
|
- |
|
|
|
- |
|
|
|
113 |
|
|
|
- |
|
|
|
|
899 |
|
|
|
- |
|
|
|
- |
|
|
|
899 |
|
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
50,252 |
|
|
|
42,811 |
|
|
|
5,382 |
|
|
|
2,028 |
|
|
|
31 |
|
|
|
December
31, 2007
|
|
|
|
|
|
|
Total
|
|
|
2007
|
|
|
2006
|
|
|
2005
|
|
|
|
|
|
|
|
(in
thousands)
|
|
|
|
|
|
Onshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
cost
|
|
|
591 |
|
|
|
591 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Exploration
cost
|
|
|
5,650 |
|
|
|
5,650 |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Acquisition
cost of undeveloped acreage
|
|
|
24,995 |
|
|
|
9,023 |
|
|
|
7,568 |
|
|
|
8,404 |
|
|
|
|
|
Capitalized
Interest
|
|
|
3,061 |
|
|
|
2,026 |
|
|
|
999 |
|
|
|
36 |
|
|
|
|
|
|
|
|
34,297 |
|
|
|
17,290 |
|
|
|
8,567 |
|
|
|
8,440 |
|
|
|
|
|
Offshore:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development
cost
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Exploration
cost
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
|
|
Acquisition
cost of undeveloped acreage
|
|
|
6,069 |
|
|
|
209 |
|
|
|
5,860 |
|
|
|
- |
|
|
|
|
|
Capitalized
Interest
|
|
|
537 |
|
|
|
381 |
|
|
|
150 |
|
|
|
6 |
|
|
|
|
|
|
|
|
6,606 |
|
|
|
590 |
|
|
|
6,010 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40,903 |
|
|
|
17,880 |
|
|
|
14,577 |
|
|
|
8,446 |
|
|
|
|
|
It is
anticipated that the acquisition of undeveloped acreage and associated
capitalized interest of $33.4 million and development and exploration costs of
$16.9 million will be included in oil and gas properties subject to amortization
within five years and one year, respectively.
Property
Acquisitions. During the fourth quarter of 2008, the Company
acquired a 90% working interest in a 1,280-acre position in the Pinedale
Anticline in the Rockies for $35.0 million and a 70% working interest in certain
properties in the Catarina Field and a 35% working interest in a significant
acreage position in the Eagle Ford shale in South Texas for $20.0 million from
Pinedale Energy, LLC and CEU W&D, LLC and W&D Gas Partners, LLC,
respectively.
During
the second quarter of 2008, the Company acquired a 50% working interest position
in approximately 12,000 gross acres in the Rockies from North American Petroleum
Corporation USA, a subsidiary of Petroflow Energy Ltd. for $29.0
million.
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
Stations. In December 2008 we purchased approximately 62 miles of
low pressure gathering from Pacific Gas and Electric for $1.3
million. The gathering system is located in the heart of the
Rio Vista field and gathers much of our low pressure production within the Rio
Vista field. The gas gathering system and compressor stations of
$39.8 million and $26.1 million at December 31, 2008 and 2007, respectively, are
primarily located in California and the Rockies, and 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, 2008 and 2007 was $5.3 million and $3.0 million,
respectively. The depreciation expense associated with the gas
gathering system and compressor stations for the years ended December 31, 2008,
2007 and 2006 was $2.2 million, $1.5 million, and $1.0 million,
respectively.
Other Property and Equipment.
Other property and equipment at December 31, 2008 and 2007 of $9.4 million and
$6.4 million, respectively, consists primarily of furniture and
fixtures. The accumulated depreciation associated with other assets
at December 31, 2008 and 2007 was $2.6 million and $1.4 million,
respectively. For the years ended December 31, 2008, 2007 and 2006
depreciation expense for other property and equipment was $1.2 million, $0.8
million, and $0.5 million, respectively.
At
December 31, 2008 and 2007, deferred loan fees were $1.2 million and $2.2
million, respectively. Total amortization expense for deferred loan fees was
$1.0 million, $1.2 million and $1.2 million for the years ended December 31,
2008, 2007 and 2006, respectively.
(6)
|
Commodity
Hedging Contracts and Other
Derivatives
|
The
following financial fixed price swap and costless collar transactions were
outstanding with associated notional volumes and average underlying prices that
represent hedged prices of commodities at various market locations at December
31, 2008:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Notional
Daily Volume
MMBtu
|
|
|
Total
of Notional Volume
MMBtu
|
|
|
Average
Floor/Fixed Prices
MMBtu
|
|
|
Average
Ceiling Prices MMBtu
|
|
|
Natural
Gas Production Hedged (1)
|
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2009
|
Swap
|
Cash
flow
|
|
|
52,141 |
|
|
|
19,031,465 |
|
|
$ |
7.65 |
|
|
$ |
- |
|
|
|
37 |
% |
|
$ |
31,082 |
|
2009
|
Costless
Collar
|
Cash
flow
|
|
|
5,000 |
|
|
|
1,825,000 |
|
|
|
8.00 |
|
|
|
10.05 |
|
|
|
4 |
% |
|
|
3,660 |
|
2010
|
Swap
|
Cash
flow
|
|
|
10,000 |
|
|
|
3,650,000 |
|
|
|
8.31 |
|
|
|
- |
|
|
|
9 |
% |
|
|
4,615 |
|
|
|
|
|
|
|
|
|
|
24,506,465 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
39,357 |
|
|
(1)
|
Estimated
based on anticipated future gas
production.
|
The
Company has hedged the interest rates on $50.0 million of its
outstanding debt through June 2009. As of December 31, 2008, the
Company had the following financial interest rate swap positions
outstanding:
Settlement
Period
|
Derivative
Instrument
|
Hedge
Strategy
|
|
Average
Fixed Rate
|
|
|
Fair
Market Value
Gain/(Loss)
(In
thousands)
|
|
2009
|
Swap
|
Cash
flow
|
|
|
4.55 |
% |
|
$ |
(985 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(985 |
) |
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, 2008, 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,
|
|
|
|
2008
|
|
|
2007
|
|
Natural
Gas
|
|
|
|
|
|
|
Quantity
settled (MMBtu)
|
|
|
26,684,616 |
|
|
|
23,464,500 |
|
Increase
(decrease) in natural gas sales revenue (In thousands)
|
|
$ |
(18,669 |
) |
|
$ |
22,926 |
|
Interest
Rate Swaps
|
|
|
|
|
|
|
|
|
Decrease
(increase) in interest expense (In thousands)
|
|
$ |
(1,158 |
) |
|
$ |
20 |
|
The
Company expects to reclassify gains of $33.8 million based on market pricing as
of December 31, 2008 to earnings from the balance in accumulated other
comprehensive income (loss) on the Consolidated Balance Sheet during the next
twelve months.
At
December 2008, the Company had derivative assets of $39.4 million, of which $4.6
million is included in other assets on the Consolidated Balance
Sheet. The Company also had derivative liabilities of $0.9 million
included in current liabilities on the Consolidated Balance Sheet at December
31, 2008.
(7)
|
Fair
Value Measurements
|
The
Company partially adopted Statement of Financial Accounting Standard No. 157,
“Fair Value Measurements” (“SFAS No. 157”) effective January 1,
2008. As defined in SFAS No. 157, fair value is the amount that would
be received to sell an asset or paid to transfer a liability in an orderly
transaction between market participants at the measurement date (“exit
price”). To estimate fair value, the Company utilizes market data or
assumptions that market participants would use in pricing the asset or
liability, including assumptions about risk and the risks inherent in the inputs
to the valuation technique. These inputs can be readily observable,
market corroborated or generally unobservable. SFAS No. 157
establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value. The hierarchy gives the
highest priority to unadjusted quoted market prices in active markets for
identical assets or liabilities (“Level 1”) and the lowest priority to
unobservable inputs (“Level 3”). The three levels of the fair value
hierarchy are as follows:
|
–
|
Level
1 inputs are quoted prices (unadjusted) in active markets for identical
assets or liabilities.
|
|
–
|
Level
2 inputs are quoted prices for similar assets and liabilities in active
markets or inputs that are observable for the asset or liability, either
directly or indirectly through market corroboration, for substantially the
full term of the financial
instrument.
|
|
–
|
Level
3 inputs are measured based on prices or valuation models that require
inputs that are both significant to the fair value measurement and less
observable from objective
sources.
|
Level 3
instruments include money market funds, natural gas swaps, natural gas zero
cost collars and interest rate swaps. The
Company’s money market funds represent cash equivalents whose investments are
limited to United States Government Securities, securities backed by the United
States Government, or securities of United States Government
agencies. The fair value represents cash held by the fund manager as
of December 31, 2008. The Company utilizes counterparty and third
party broker quotes to determine the valuation of its derivative
instruments. Fair values derived from counterparties and brokers are
further verified using the closing price as of December 31, 2008 for the
relevant NYMEX futures contracts and Intercontinental Exchange traded
contracts for each derivative settlement location.
The
following table sets forth by level within the fair value hierarchy the
Company’s financial assets and liabilities that were accounted for at fair value
on a recurring basis as of December 31, 2008. As required by SFAS No. 157,
financial assets and liabilities are classified in their entirety based on the
lowest level of input that is significant to the fair value measurement. The
Company’s assessment of the significance of a particular input to the fair value
measurement requires judgment and may affect the valuation of fair value assets
and liabilities and their placement within the fair value hierarchy
levels.
|
|
At
fair value as of December 31, 2008
(In
thousands)
|
|
|
|
Level
1
|
|
|
Level
2
|
|
|
Level
3
|
|
|
Total
|
|
Assets
(Liabilities):
|
|
|
|
|
|
|
|
|
|
|
|
|
Money
market funds
|
|
|
|
|
|
|
- |
|
|
|
5,025 |
|
|
|
5,025 |
|
Commodity
derivative contracts
|
|
|
- |
|
|
|
- |
|
|
|
39,357 |
|
|
|
39,357 |
|
Interest
rate swap contracts
|
|
|
- |
|
|
|
- |
|
|
|
(985 |
) |
|
|
(985 |
) |
Total
|
|
|
|
|
|
|
- |
|
|
|
43,397 |
|
|
|
43,397 |
|
The
determination of the fair values above incorporates various factors required
under SFAS No. 157. These factors include the credit standing of the
counterparties involved, the impact of credit enhancements and the impact of the
Company’s nonperformance risk on its liabilities. The Company considered credit
adjustments for the counterparties using current credit default swap values and
default probabilities for each counterparty in determining fair
value.
The table
below presents a reconciliation for the assets and liabilities classified as
Level 3 in the fair value hierarchy during 2008. Level 3 instruments
presented in the table consist of net derivatives that, in management’s
judgment, reflect the assumptions a marketplace participant would have used at
December 31, 2008.
|
|
Derivatives
|
|
|
|
|
|
|
|
|
|
Asset
(Liability)
|
|
|
Investments
|
|
|
Total
|
|
|
|
(In
thousands)
|
|
Balance
as of January 1, 2008
|
|
$ |
(10,792 |
) |
|
|
- |
|
|
|
(10,792 |
) |
Total
(gains) losses (realized or unrealized)
|
|
|
|
|
|
|
|
|
|
|
|
|
included
in earnings
|
|
|
- |
|
|
|
25 |
|
|
|
25 |
|
included
in other comprehensive income
|
|
|
29,337 |
|
|
|
- |
|
|
|
29,337 |
|
Purchases,
issuances and settlements
|
|
|
19,827 |
|
|
|
5,000 |
|
|
|
24,827 |
|
Transfers
in and out of level 3
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Balance
as of December 31, 2008
|
|
$ |
38,372 |
|
|
$ |
5,025 |
|
|
$ |
43,397 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The
amount of total gains or losses for the period included in earnings
attributable to the change in unrealized gains or losses relating to
assets still held at December 31, 2008
|
|
$ |
- |
|
|
$ |
- |
|
|
$ |
- |
|
The
Company’s accrued liabilities consist of the following:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Accrued
capital costs
|
|
$ |
26,555 |
|
|
$ |
34,599 |
|
Accrued
purchase price adjustments
|
|
|
- |
|
|
|
11,400 |
|
Accrued
payroll and employee incentive expense
|
|
|
5,721 |
|
|
|
5,361 |
|
Accrued
lease operating expense
|
|
|
12,196 |
|
|
|
4,930 |
|
Asset
retirement obligation
|
|
|
1,359 |
|
|
|
4,629 |
|
Other
|
|
|
2,993 |
|
|
|
3,297 |
|
Total
|
|
$ |
48,824 |
|
|
$ |
64,216 |
|
(9)
|
Asset
Retirement Obligation
|
Activity
related to the Company’s asset retirement obligation (“ARO”) is as
follows:
|
|
For
the Year Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
ARO
as of the beginning of the period
|
|
$ |
22,670 |
|
|
$ |
10,689 |
|
Revision
of previous estimate
|
|
|
1,785 |
|
|
|
9,751 |
|
Liabilities
incurred during period
|
|
|
1,727 |
|
|
|
2,105 |
|
Liabilities
settled during period
|
|
|
(363 |
) |
|
|
(1,355 |
) |
Accretion
expense
|
|
|
2,125 |
|
|
|
1,480 |
|
ARO
as of the end of the period
|
|
$ |
27,944 |
|
|
$ |
22,670 |
|
Of the
total ARO, approximately $1.4 million and $4.6 million are included in accrued
liabilities on the Consolidated Balance Sheet at December 31, 2008 and 2007,
respectively.
Long-term
debt consists of the following:
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Senior
secured revolving line of credit
|
|
$ |
225,000 |
|
|
$ |
170,000 |
|
Second
lien term loan
|
|
|
75,000 |
|
|
|
75,000 |
|
|
|
|
300,000 |
|
|
|
245,000 |
|
Less:
current portion of long-term debt
|
|
|
- |
|
|
|
- |
|
|
|
$ |
300,000 |
|
|
$ |
245,000 |
|
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. 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 June 2008, the borrowing base was adjusted to $400.0 million and affirmed in
December 2008. The next borrowing base review is scheduled to begin
on March 2, 2009. 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%. These rates over LIBOR were adjusted in June
2008 to be 1.125% to 1.875%. 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
membership interests 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. At December 31, 2008, the Company’s current ratio was
2.7 and the leverage ratio was 0.8. 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, 2008. As of December 31, 2008, the Company had
$175.0 million available for borrowing under their revolving line of credit. All
amounts drawn under the Revolver are due and payable on April 5,
2010.
Second Lien Term Loan.
BNP Paribas, in July 2005, also provided the Company
with a second lien term loan concurrent with the acquisition of oil and gas
properties from Calpine (“Term Loan”). Borrowings under the Term Loan
are $75.0 million as of December 31, 2008. Such borrowings are
syndicated to a group of lenders including BNP Paribas. Borrowings
under the Term Loan bear interest at LIBOR plus 4.00%. 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. At December 31, 2008, the
Company’s asset coverage ratio was 3.1 and the leverage ratio was
0.8. 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, 2008. The
principal balance of the Term Loan is due and payable on July 7,
2010.
The
Company’s 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 the Company’s liquidity
position. The Company has already begun the process of extending the
maturity of its revolving credit facility and second lien term
loan. If the Company is unable to extend the maturity of the
revolving credit facility, it will become a current liability on April 5, 2009
and would result in the Company being in default with respect to the working
capital covenants in the revolving credit facility and second lien term
loan. The Company believes that it will be successful in extending
this maturity on acceptable terms and conditions. Similarly, if the
Company is unable to extend the maturity of the second lien term loan, it will
become a current liability on July 7, 2009. Current market conditions
could result in increased costs of borrowing.
Aggregate
maturities of long-term debt at December 31, 2008 due in the next five
years are $300 million in 2010.
(11)
|
Commitments
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
Settlement
On
December 20, 2005, Calpine Corporation and certain of its subsidiaries filed for
protection under the federal bankruptcy laws in the Bankruptcy
Court. Two years later, on December 19, 2007, the Bankruptcy Court
confirmed a plan of reorganization for Calpine, which emerged from bankruptcy on
January 31, 2008. During that period, on June 29, 2007, Calpine
commenced the Lawsuit. Over the next fourteen months, the Company
vigorously disputed Calpine’s contentions in the Lawsuit, including any and all
allegations that it underpaid for Calpine’s oil and gas business.
On October
22, 2008, Calpine and the Company announced that they had entered into a
comprehensive settlement agreement (the “Settlement Agreement”) which, among
other things, would (i) resolve all claims in the Lawsuit, (ii) result in
Calpine conveying clean legal title on all remaining oil and gas assets to
Rosetta (except those properties subject to the preferential rights of third
parties who have indicated a desire to exercise their rights), (iii) settle all
pending claims the Company filed in the Calpine bankruptcy, (iv) modify and
extend a gas purchase agreement by which Calpine purchases the Company’s
dedicated production from the Sacramento Valley, California, and (v) formalize
the assumption by Calpine of the July 7, 2005 purchase and sale agreement
(together with all interrelated agreements, the “Purchase Agreement”) by which
Calpine’s oil and gas business was conveyed to the Company thus resulting in the
parties honoring their obligations under the Purchase Agreement on a
going-forward basis. The Settlement Agreement became effective when
the Bankruptcy Court entered its order on November 13, 2008, authorizing the
execution of the Settlement Agreement and the performance of the obligations set
forth therein. No objections or appeals to this order were filed or taken with
the Bankruptcy Court before or after the hearing on November 13, 2008, and it
became final on or about November 23, 2008.
The
parties completed this settlement pursuant to the terms of the Settlement
Agreement on December 1, 2008. The cash component of the settlement consisted of
$12.4 million pre-tax payable in cash to Calpine to resolve all outstanding
legal disputes regarding various matters, including Calpine’s fraudulent
conveyance lawsuit. In addition, the Company paid $84.6 million under the
Purchase Agreement to close the original acquisition transaction of the
producing properties that were the subject of the lawsuit. This $84.6 million
consisted of $67.6 million, which the Company withheld from the purchase price
at the closing on July 7, 2005, related to non-consent properties (excluding the
properties subject to preferential rights) that were not conveyed to the Company
at closing on July 7, 2005, as well as $17.0 million for various disputed
post-closing adjustments under the terms of the Purchase Agreement, as amended
by the Bankruptcy Court order to remove the properties that had been subject to
the Petersen preferential rights as if these properties had not been part of the
Purchase Agreement.
As a
result of the conclusion of this settlement, the Company recorded a pre-tax
charge of $12.4 million in the fourth quarter of 2008, which is included in
Other Income (Expense) in the Consolidated Statement of Operations.
Arbitration
between the Company and the successor to Pogo Producing
Company
On
October 27, 2008, the Company, Calpine and XTO, as the successor to Pogo, agreed
to a Title Indemnity Agreement in which Calpine agreed to indemnify XTO for
certain title disputes, and the Company, Calpine and XTO agreed to dismissal of
the arbitration proceeding against the Company and release of Pogo’s proofs of
claim. The Company’s proofs of claim were resolved within the framework of the
Settlement Agreement with Calpine, which was approved by the Bankruptcy Court
and an order issued in this regard. XTO has dismissed with prejudice
the arbitration against the Company.
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 $3.3 million, $2.6 million and
$2.4 million for the years ended December 31, 2008, 2007 and 2006,
respectively.
Future
minimum annual rental commitments under non-cancelable leases at
December 31, 2008 are as follows (In thousands):
2009
|
|
$ |
3,055 |
|
2010
|
|
|
2,972 |
|
2011
|
|
|
3,049 |
|
2012
|
|
|
3,074 |
|
2013
|
|
|
3,130 |
|
Thereafter
|
|
|
513 |
|
|
|
$ |
15,793 |
|
The
Company also has drilling rig commitments of $5.0 million for 2009.
(12)
|
Stock-Based
Compensation
|
Effective
January 1, 2006, the Company began accounting for stock-based compensation under
SFAS No. 123R, whereby the Company records stock-based compensation expense
based on the fair value of awards described below. Stock-based
compensation expense recorded for all share-based payment arrangements for the
years ended December 31, 2008, 2007 and 2006 was $7.2 million, $6.8 million and
$5.7 million, respectively, with an associated tax benefit of $2.9 million,
$2.5 million and $2.1 million, respectively. The remaining
unrecognized compensation expense associated with total unvested awards as of
December 31, 2008 was $9.8 million.
2005
Long-Term Incentive Plan
In July
2005, the Board of Directors adopted the Rosetta 2005 Long-Term Incentive Plan
(the “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
was increased from 3,000,000 shares to 4,950,000 shares by vote of the
shareholders in 2008. The shares available for grant include these
4,950,000 shares 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 (the
“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, 2008, 2007 and 2006 was $9.19 per share, $9.51 per
share, and $10.71 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,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
Expected
option term (years)
|
|
|
6.5 |
|
|
|
6.5 |
|
|
|
6.5 |
|
Expected
volatility
|
|
|
42.45 |
% |
|
|
42.45 |
% |
|
|
56.65 |
% |
Expected
dividend rate
|
|
|
0.00 |
% |
|
|
0.00 |
% |
|
|
0.00 |
% |
Risk
free interest rate
|
|
|
3.48%
- 3.84 |
% |
|
|
4.36%
- 5.00 |
% |
|
|
4.33%
- 5.15 |
% |
The
Company has assumed an annual forfeiture rate of 11% for the options granted in
2008 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.
The
following table summarizes information related to outstanding and exercisable
options held by the Company’s employees and directors at December 31,
2008:
|
|
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 |
|
|
|
|
|
|
|
|
|
Granted
|
|
|
209,375 |
|
|
|
19.13 |
|
|
|
|
|
|
|
|
|
Exercised
|
|
|
(214,119 |
) |
|
|
16.89 |
|
|
|
|
|
|
|
|
|
Forfeited
|
|
|
(26,100 |
) |
|
|
17.57 |
|
|
|
|
|
|
|
|
|
Outstanding
at December 31, 2008
|
|
|
941,756 |
|
|
$ |
17.94 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options
Vested and Exercisable at December 31, 2008
|
|
|
629,155 |
|
|
$ |
17.76 |
|
|
|
7.34 |
|
|
$ |
- |
|
Stock-based
compensation expense recorded for stock option awards for the years ended
December 31, 2008, 2007 and 2006 was $1.7 million, $3.9 million and $2.9
million, respectively. Unrecognized expense as of December 31, 2008
for all outstanding stock options is $1.4 million and will be recognized over a
weighted average period of 0.92 years.
The total
intrinsic value of options exercised during the years ended December 31, 2008,
2007 and 2006 is $1.4 million, $0.2 million and $0.1 million,
respectively.
Restricted
Stock
The
Company has granted restricted 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
11% 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 and directors at December 31, 2008:
|
|
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 |
|
Granted
|
|
|
607,079 |
|
|
|
20.06 |
|
Vested
|
|
|
(274,714 |
) |
|
|
18.31 |
|
Forfeited
|
|
|
(70,351 |
) |
|
|
19.54 |
|
Non-vested
shares outstanding at December 31, 2008
|
|
|
717,439 |
|
|
$ |
19.78 |
|
The
non-vested restricted stock outstanding at December 31, 2008 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, 2008 was $6.2
million.
Stock-based
compensation expense recorded for restricted stock awards for the years ended
December 31, 2008, 2007 and 2006 was $5.5 million, $2.9 million and $2.8
million, respectively. Unrecognized expense as of December 31, 2008
for all outstanding restricted stock awards is $8.5 million and will be
recognized over a weighted average period of 1.78 years.
The
Company’s income tax expense (benefit) consists of the following:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Current:
|
|
|
|
|
|
|
|
|
|
Federal
|
|
$ |
2,304 |
|
|
$ |
- |
|
|
$ |
- |
|
State
|
|
|
1,388 |
|
|
|
115 |
|
|
|
172 |
|
|
|
|
3,692 |
|
|
|
115 |
|
|
|
172 |
|
Deferred:
|
|
|
|
|
|
|
|
|
|
|
|
|
Federal
|
|
|
(107,568 |
) |
|
|
31,979 |
|
|
|
24,132 |
|
State
|
|
|
(8,951 |
) |
|
|
1,938 |
|
|
|
3,340 |
|
|
|
|
(116,519 |
) |
|
|
33,917 |
|
|
|
27,472 |
|
Total
income tax expense (benefit)
|
|
$ |
(112,827 |
) |
|
$ |
34,032 |
|
|
$ |
27,644 |
|
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:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
(In
thousands)
|
|
|
(%)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
US
Statutory Rate
|
|
$ |
(105,327 |
) |
|
|
35.0 |
% |
|
$ |
31,933 |
|
|
|
35.0 |
% |
|
$ |
25,288 |
|
|
|
35.0 |
% |
Income/franschise
tax, net of federal benefit
|
|
|
(7,562 |
) |
|
|
2.5 |
% |
|
|
2,053 |
|
|
|
2.3 |
% |
|
|
2,283 |
|
|
|
3.2 |
% |
Permanent
differences and other
|
|
|
62 |
|
|
|
0.0 |
% |
|
|
46 |
|
|
|
0.0 |
% |
|
|
73 |
|
|
|
0.0 |
% |
Total
tax expense (Benefit)
|
|
$ |
(112,827 |
) |
|
|
37.5 |
% |
|
$ |
34,032 |
|
|
|
37.3 |
% |
|
$ |
27,644 |
|
|
|
38.2 |
% |
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,
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Deferred
tax assets
|
|
|
|
|
|
|
Oil
and gas properties basis differences
|
|
$ |
39,089 |
|
|
$ |
- |
|
Alternative
Minimum Tax credit
|
|
|
2,443 |
|
|
|
- |
|
Accrued
liabilities not currently deductible
|
|
|
2,603 |
|
|
|
3,273 |
|
Hedge
activity
|
|
|
- |
|
|
|
4,289 |
|
Net
operating loss carryforward
|
|
|
621 |
|
|
|
12,506 |
|
Other
|
|
|
1,158 |
|
|
|
892 |
|
Total
deferred tax assets
|
|
|
45,914 |
|
|
|
20,960 |
|
Oil
and gas properties basis differences
|
|
|
- |
|
|
|
(89,397 |
) |
Hedge
activity
|
|
|
(14,294 |
) |
|
|
- |
|
Other
|
|
|
(1,543 |
) |
|
|
(200 |
) |
Total
gross deferred tax liabilities
|
|
|
(15,837 |
) |
|
|
(89,597 |
) |
Net
deferred tax assets (liabilities)
|
|
$ |
30,077 |
|
|
$ |
(68,637 |
) |
At
December 31, 2008, the Company had a deferred tax asset related to federal
and state net operating loss carryforwards of approximately $1.5
million. The net operating loss carryforward will begin to expire in
2025. Additionally, the Company had a deferred tax asset related to
oil and gas properties basis of $39.1 million. 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.
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, 2008 and 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:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Basic
weighted average number of shares outstanding
|
|
|
50,693 |
|
|
|
50,379 |
|
|
|
50,237 |
|
Dilution
effect of stock option and awards at the end of the
period
|
|
|
- |
|
|
|
210 |
|
|
|
171 |
|
Diluted
weighted average number of shares outstanding
|
|
|
50,693 |
|
|
|
50,589 |
|
|
|
50,408 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Anti-dilutive
stock options and awards
|
|
|
592 |
|
|
|
385 |
|
|
|
198 |
|
Because
the Company recognized a net loss for the year ended December 31, 2008, no
unvested stock awards and options were included in computing earnings per share
because the effect was anti-dilutive. In computing earnings per
share, no adjustments were made to reported net income.
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.
|
|
Year
Ended December 31,
|
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
2006
(1)
|
|
Oil
and Natural Gas Revenue
|
|
(In
thousands)
|
|
California
|
|
$ |
141,569 |
|
|
$ |
110,607 |
|
|
$ |
76,408 |
|
Rockies
|
|
|
29,491 |
|
|
|
10,676 |
|
|
|
2,115 |
|
South
Texas
|
|
|
204,791 |
|
|
|
143,886 |
|
|
|
100,988 |
|
Texas
State Waters
|
|
|
49,745 |
|
|
|
8,789 |
|
|
|
8,183 |
|
Other
Onshore
|
|
|
44,809 |
|
|
|
25,905 |
|
|
|
27,757 |
|
Gulf
of Mexico
|
|
|
47,611 |
|
|
|
40,700 |
|
|
|
26,734 |
|
|
|
$ |
518,016 |
|
|
$ |
340,563 |
|
|
$ |
242,185 |
|
|
|
December
31,
|
|
|
|
2008
|
|
|
2007
|
|
Oil
and Natural Gas Properties
|
|
(In
thousands)
|
|
California
|
|
$ |
619,593 |
|
|
$ |
540,924 |
|
Rockies
|
|
|
175,294 |
|
|
|
76,343 |
|
South
Texas
|
|
|
712,464 |
|
|
|
591,355 |
|
Texas
State Waters
|
|
|
65,085 |
|
|
|
55,918 |
|
Other
Onshore
|
|
|
171,855 |
|
|
|
145,675 |
|
Gulf
of Mexico
|
|
|
156,381 |
|
|
|
155,867 |
|
Other
|
|
|
9,439 |
|
|
|
6,393 |
|
|
|
$ |
1,910,111 |
|
|
$ |
1,572,475 |
|
___________________________________
|
(1)
|
Excludes
the effects of hedging losses of $18.7 million for the year ended December
31, 2008 and hedging gains of $22.9 million and $29.6 million for the
years ended December 31, 2007 and 2006,
respectively.
|
Major
Customers
For the
year ended December 31, 2008, the Company had one major customer, Calpine Energy
Services (“CES”), a Calpine affiliate, which accounted for approximately 61% of
the Company’s consolidated annual revenue. The Company’s annual
consolidated revenue from CES accounted for approximately 55% for the year ended
December 31, 2007 and 45% for the year ended December 31, 2006, respectively,
and is reflected in oil and natural gas sales.
For the
years ended December 31, 2008, 2007 and 2006, revenues from sales to CES were
$305.9 million, $201.4 million, and $99.1 million,
respectively. There was no receivable from CES at December 31,
2008 or 2007. 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, 2008 and 2007, the Company had $19.4 million and
$20.4 million in the margin account for December sales to CES which is included
in Accrued Liabilities on the Consolidated Balance Sheet.
Marketing
Services Agreement
The
Company entered into a new marketing services agreement (“MSA”) with Calpine
Producer Services (“CPS”) in connection with the partial transfer and release
agreement (“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%, subject to caps imposed under the MSA. For the years ended December
31, 2008, 2007 and 2006, the fee was approximately $3.1 million,
$2.5 million, and $2.3 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. The MSA will expire in
June 2009 and the Company does not have intentions of renewing the
MSA. The Company is expanding its internal capabilities in this
regard so as to be able to market in-house all of its oil and gas production at
the conclusion of the MSA.
(16)
|
Related
Party Transactions
|
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 former 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.
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,
2008, 2007, and 2006, 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
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 qualified, 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, 2008 and
2007:
|
|
|
|
|
|
|
|
|
2008
|
|
|
2007
|
|
|
|
(In
thousands)
|
|
Proved
properties
|
|
$ |
1,813,527 |
|
|
$ |
1,499,046 |
|
Unproved
properties
|
|
|
50,252 |
|
|
|
40,903 |
|
Total
|
|
|
1,863,779 |
|
|
|
1,539,949 |
|
Less:
Accumulated depreciation, depletion, and amortization
|
|
|
(927,961 |
) |
|
|
(291,321 |
) |
Net
capitalized costs
|
|
$ |
935,818 |
|
|
$ |
1,248,628 |
|
Pursuant
to SFAS No. 143 “Accounting for Asset Retirement Obligations”, net
capitalized costs include asset retirement costs of $23.2 million and $20.1
million as of December 31, 2008 and 2007, 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, 2008, 2007 and
2006:
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
thousands)
|
|
Acquisition
costs of properties
|
|
|
|
|
|
|
|
|
|
Proved
|
|
$ |
103,177 |
|
|
$ |
40,760 |
|
|
$ |
39,194 |
|
Unproved
|
|
|
32,276 |
|
|
|
23,824 |
|
|
|
22,317 |
|
Subtotal
|
|
|
135,453 |
|
|
|
64,584 |
|
|
|
61,511 |
|
Exploration
costs
|
|
|
35,735 |
|
|
|
90,117 |
|
|
|
48,446 |
|
Development
costs
|
|
|
152,260 |
|
|
|
178,894 |
|
|
|
125,971 |
|
Total
|
|
$ |
323,448 |
|
|
$ |
333,595 |
|
|
$ |
235,928 |
|
Results
of operations for oil and natural gas producing activities
|
|
Year
Ended December 31,
|
|
|
|
2008
(1)
|
|
|
2007
(1)
|
|
|
2006
(1)
|
|
|
|
|
|
|
|
|
|
|
|
Oil
and natural gas producing revenues
|
|
$ |
518,016 |
|
|
$ |
340,563 |
|
|
$ |
242,185 |
|
Total
Revenues
|
|
|
518,016 |
|
|
|
340,563 |
|
|
|
242,185 |
|
Production
costs
|
|
|
78,609 |
|
|
|
60,140 |
|
|
|
47,507 |
|
Depreciation,
depletion, and amortization
|
|
|
198,862 |
|
|
|
152,882 |
|
|
|
105,886 |
|
Impairment
of oil and gas properties
|
|
|
444,369 |
|
|
|
- |
|
|
|
- |
|
Income
before income taxes
|
|
|
(203,824 |
) |
|
|
127,541 |
|
|
|
88,792 |
|
Income
tax provision
|
|
|
(76,434 |
) |
|
|
47,573 |
|
|
|
34,007 |
|
Results
of operations
|
|
$ |
(127,390 |
) |
|
$ |
79,968 |
|
|
$ |
54,785 |
|
___________________________________
|
(1)
|
Excludes
the effects of hedging losses of $18.7 million for the year ended December
31, 2008 and hedging gains of $22.9 million and $29.6 million for the
years ended December 31, 2007 and 2006,
respectively.
|
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, 2008, 2007, and
2006, as estimated by the independent petroleum consultants and the changes in
the net proved reserves for each of the three years then ended.
|
|
|
|
|
Natural
gas liquids
|
|
|
|
|
|
|
Natural
gas
|
|
|
and
crude oil
|
|
|
Bcfe
(1)
|
|
|
|
(Bcf)(1):
|
|
|
(MBbl)(2)(3):
|
|
|
equivalents
(4):
|
|
|
|
|
|
|
|
|
|
|
|
Net
proved reserves at December 31, 2005 (5)
|
|
|
345 |
|
|
|
2,481 |
|
|
|
359 |
|
Revisions
of previous estimates
|
|
|
(10 |
) |
|
|
424 |
|
|
|
(7 |
) |
Purchases
in place
|
|
|
4 |
|
|
|
286 |
|
|
|
6 |
|
Extensions,
discoveries and other additions
|
|
|
81 |
|
|
|
315 |
|
|
|
83 |
|
Sales
in place
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Production
|
|
|
(30 |
) |
|
|
(576 |
) |
|
|
(33 |
) |
Net
proved reserves at December 31, 2006 (5)
|
|
|
390 |
|
|
|
2,930 |
|
|
|
408 |
|
Revisions
of previous estimates
|
|
|
(30 |
) |
|
|
- |
|
|
|
(30 |
) |
Purchases
in place
|
|
|
10 |
|
|
|
- |
|
|
|
10 |
|
Extensions,
discoveries and other additions
|
|
|
72 |
|
|
|
652 |
|
|
|
76 |
|
Sales
in place
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Production
|
|
|
(42 |
) |
|
|
(561 |
) |
|
|
(46 |
) |
Net
proved reserves at December 31, 2007 (5)
|
|
|
400 |
|
|
|
3,021 |
|
|
|
418 |
|
Revisions
of previous estimates (6)
|
|
|
(77 |
) |
|
|
779 |
|
|
|
(72 |
) |
Purchases
in place
|
|
|
63 |
|
|
|
293 |
|
|
|
65 |
|
Extensions,
discoveries and other additions
|
|
|
38 |
|
|
|
418 |
|
|
|
40 |
|
Sales
in place
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
Production
|
|
|
(48 |
) |
|
|
(908 |
) |
|
|
(53 |
) |
Net
proved reserves at December 31, 2008
|
|
|
376 |
|
|
|
3,603 |
|
|
|
398 |
|
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, 2006 (5)
|
|
|
251 |
|
|
|
1,965 |
|
|
|
263 |
|
December
31, 2007 (5)
|
|
|
286 |
|
|
|
2,658 |
|
|
|
302 |
|
December
31, 2008
|
|
|
308 |
|
|
|
3,253 |
|
|
|
327 |
|
___________________________________
|
(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)
|
Excludes
estimated reserves pertaining to interests in certain leases and wells
associated with the Non-Consent
Properties.
|
|
(6)
|
Downward
revision of 64 Bcfe of proved reserves and 8 Bcfe due to year-end
commodity prices.
|
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, 2008, 2007 and 2006.
|
|
Year
Ended December 31,
|
|
|
|
2008
|
|
|
2007
|
|
|
2006
|
|
|
|
(In
millions)
|
|
|
|
|
|
|
|
|
|
|
|
Future
cash inflows
|
|
$ |
2,437 |
|
|
$ |
3,026 |
|
|
$ |
2,452 |
|
Future
production costs
|
|
|
(776 |
) |
|
|
(819 |
) |
|
|
(684 |
) |
Future
development costs
|
|
|
(269 |
) |
|
|
(302 |
) |
|
|
(312 |
) |
Future
income taxes
|
|
|
(166 |
) |
|
|
(323 |
) |
|
|
(182 |
) |
Future
net cash flows
|
|
|
1,226 |
|
|
|
1,582 |
|
|
|
1,274 |
|
Discount
to present value at 10% annual rate
|
|
|
(485 |
) |
|
|
(628 |
) |
|
|
(552 |
) |
Standardized
measure of discounted future net cash flows relating to proved natural
gas, natural gas liquids and crude oil reserves
|
|
$ |
741 |
|
|
$ |
954 |
|
|
$ |
722 |
|
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, 2008, 2007 and 2006.
|
|
(In
millions)
|
|
Balance
December 31, 2005 (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 (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 (1)
|
|
|
954 |
|
Sales
and transfers of natural gas, natural gas liquids and crude oil produced,
net of production costs
|
|
|
(439 |
) |
Net
changes in prices and production costs
|
|
|
(73 |
) |
Extensions,
discoveries, additions and improved recovery, net of related
costs
|
|
|
123 |
|
Development
costs incurred
|
|
|
98 |
|
Revisions
of previous quantity estimates and development costs
|
|
|
(191 |
) |
Accretion
of discount
|
|
|
114 |
|
Net
change in income taxes
|
|
|
95 |
|
Purchases
of reserve in place
|
|
|
119 |
|
Sales
of reserves in place
|
|
|
- |
|
Changes
in timing and other
|
|
|
(59 |
) |
Balance
December 31, 2008
|
|
$ |
741 |
|
___________________________________
(1)
|
Excludes
non-consent properties - see Note
11.
|
Rosetta
Resources Inc.
Selected
Data
Quarterly
Information
(Unaudited)
Summaries
of the Company’s results of operations by quarter for the years ended 2008 and
2007 are as follows:
|
|
2008
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
|
(In
thousands, except per share data)
|
|
Revenues
|
|
$ |
128,333 |
|
|
$ |
154,467 |
|
|
$ |
130,036 |
|
|
$ |
86,512 |
|
Impairment
of oil and gas properties
|
|
|
- |
|
|
|
- |
|
|
|
(205,659 |
) |
|
|
(238,710 |
) |
Operating
Income
|
|
|
45,908 |
|
|
|
66,730 |
|
|
|
(155,806 |
) |
|
|
(232,170 |
) |
Net
Income
|
|
|
27,489 |
|
|
|
39,315 |
|
|
|
(99,375 |
) |
|
|
(155,539 |
) |
Basic
earnings per share
|
|
$ |
0.54 |
|
|
$ |
0.78 |
|
|
$ |
(1.96 |
) |
|
$ |
(3.06 |
) |
Diluted
earnings per share
|
|
$ |
0.54 |
|
|
$ |
0.77 |
|
|
$ |
(1.96 |
) |
|
$ |
(3.06 |
) |
|
|
2007
|
|
|
|
First
Quarter
|
|
|
Second
Quarter
|
|
|
Third
Quarter
|
|
|
Fourth
Quarter
|
|
|
|
(In
thousands, except per share data)
|
|
Revenues
|
|
$ |
75,796 |
|
|
$ |
86,874 |
|
|
$ |
89,718 |
|
|
$ |
111,101 |
|
Impairment
of oil and gas properties
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
|
|
- |
|
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 |
|
|
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, 2008.
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 (i) recorded, processed, summarized and reported
within the time periods specified in Securities and Exchange Commission’s rules
and forms, and (ii) 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, 2008, our disclosure controls and procedures
were effective.
Management’s
Annual 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, 2008 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, 2008, 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, 2008, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report, which
is included in Item 8. Financial Statements and Supplementary Data 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, 2008 that has materially affected, or is reasonably
likely to materially affect, our internal control over financial
reporting.
Item
5.02(e). Departure of Directors or Certain Officers; Election of Directors;
Appointment of Certain Officers; Compensatory Arrangements of Certain
Officers.
On
February 23, 2009, the Compensation Committee amended and restated the 2005
Long-Term Incentive Plan. The amended and restated 2005 Long-Term
Incentive Plan is attached hereto as Exhibit 10.9. These
amendments were not material. Additionally, on February 23, 2009,
the Compensation Committee adopted the 2005 Long-Term Incentive Plan Performance
Share Unit Award Agreement which is attached hereto as Exhibit
10.39. This is a
form of agreement for performance share unit awards to be made under the 2005
Long-Term Incentive Plan. Because this Annual Report on Form 10-K is
being filed within four business days from February 23, 2009, the amendment and
restatement of the 2005 Long-Term Incentive Plan and the adoption of the 2005
Long-Term Incentive Plan Performance Share Unit Award Agreement are being
disclosed hereunder rather than under Item 5.02(e) of Form
8-K.
PART
III
|
Directors,
Executive Officers and Corporate
Governance
|
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 2009 annual
meeting under the headings “Security Ownership of Directors and Executive
Officers,” “Company Nominees for Director,” “Section 16(a) Beneficial Ownership
Reporting Compliance,” and “Corporate Governance and Committees of the
Board.”
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 2009 annual
meeting under the headings “Executive Compensation,” “Information Concerning the
Board of Directors,” and “Compensation Committee Report.”
|
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 2009 annual
meeting under the headings ”Security Ownership of Certain Beneficial Owners and
Management” and “Securities Authorized for Issuance Under Equity Compensation
Plans.”
|
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 2009 annual
meeting under the heading “Certain Transactions” and “Corporate Governance and
Committees of the Board.”
|
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 2009 annual
meeting under the heading “Audit and Non-Audit Fees Summary.”
Part
IV
|
Exhibits
and Financial Statement Schedules
|
|
a.
|
The
following documents are filed as a part of this report or incorporated
herein by reference:
|
|
(1)
|
Our
Consolidated Financial Statements are listed on page 42 of this
report.
|
|
(2)
|
Financial
Statement Schedules:
|
None
The
following documents are included as exhibits to this report:
Exhibit
Number
|
|
Description
|
|
|
|
|
|
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)).
|
|
|
|
|
|
Amended
and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to
the Company’s Current Report on Form 8-K filed on December 10, 2008
(Registration No. 000-51801)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
Settlement
Agreement and Amendment with Calpine Corporation attached hereto as
Exhibit 10.3.
|
|
|
|
|
|
Amended
and Restated Base Contract for Sale and Purchase of Natural Gas with
Calpine Energy Services, L.P. attached hereto as Exhibit
10.4.
|
|
|
|
|
|
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)).
|
|
|
|
|
|
Amended
and Restated 2005 Long-Term Incentive Plan attached hereto as Exhibit
10.9.
|
|
|
|
|
|
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)).
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
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)).
|
|
|
|
|
|
Second
Amendment to Senior Revolving Credit Agreement attached hereto as Exhibit
10.27.
|
|
|
|
|
|
Second
Amendment to Second Lien Term Loan Agreement attached hereto as Exhibit
10.28.
|
|
|
|
|
|
Third
Amendment to Senior Revolving Credit Agreement attached hereto as Exhibit
10.29.
|
|
|
|
|
|
Third
Amendment to Second Lien Term Loan Agreement attached hereto as Exhibit
10.30.
|
|
|
|
|
|
Amended
and Restated Employment Agreement with Randy L. Limbacher
attached hereto as Exhibit 10.31.
|
|
|
|
|
|
Amended
and Restated Employment Agreement with Michael J. Rosinski attached hereto
as Exhibit 10.32.
|
|
|
|
|
|
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).
|
|
|
|
|
|
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).
|
|
|
|
|
|
Marketing
and Related Services Agreement with Calpine Natural Gas Services, L.P.
(incorporated herein by reference to Exhibit 10.5 to Form 10-Q filed
November 9, 2007).
|
|
|
|
|
|
Indemnification
Agreement with Directors and Officers 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 (incorporated
herein by reference to Exhibit 10.38 to Form 10-K filed February 29,
2008).
|
|
|
|
|
|
2005
Long-Term Incentive Plan Performance Share Unit Award Agreement attached
hereto as Exhibit 10.39.
|
|
|
|
|
|
Executive
Employee Change of Control Plan attached hereto as Exhibit
10.40.
|
|
|
|
|
|
Executive
Employee Severance Plan attached hereto as Exhibit
10.41.
|
|
|
|
|
|
Fourth
Amendment to Senior Revolving Credit Agreement (incorporated herein by
reference to Exhibit 10.42 to Form 10-Q filed August 8,
2008).
|
|
|
|
|
|
Fourth
Amendment to Second Lien Term Loan Agreement(incorporated herein by
reference to Exhibit 10.43 to Form 10-Q filed August 8,
2008).
|
|
|
|
|
|
Subsidiaries
of the registrant
|
|
|
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.
|
Signatures
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf by
the undersigned thereunto duly authorized, on February 27, 2009.
|
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
27, 2009 |
Randy
L. Limbacher
|
|
(Principal
Executive Officer)
|
|
|
|
|
|
|
|
/s/ Michael J. Rosinski
|
|
Executive
Vice President and Chief Financial
|
|
February
27, 2009
|
Michael
J. Rosinski
|
|
Officer
(Principal Financial Officer)
|
|
|
|
|
|
|
|
/s/ Denise DuBard
|
|
Vice
President, Controller
|
|
February
27, 2009
|
Denise
DuBard
|
|
(Principal
Accounting Officer)
|
|
|
|
|
|
|
|
/s/ D. Henry Houston
|
|
Non-Executive
Chairman, Director
|
|
February
27, 2009
|
D.
Henry Houston
|
|
|
|
|
|
|
|
|
|
/s/ Richard W. Beckler
|
|
Director
|
|
February
27, 2009
|
Richard
W. Beckler
|
|
|
|
|
|
|
|
|
|
/s/ Matt Fitzgerald
|
|
Director
|
|
February
27, 2009
|
Matt
Fitzgerald
|
|
|
|
|
|
|
|
|
|
/s/ Philip L. Frederickson
|
|
Director
|
|
February
27, 2009
|
Philip
L. Frederickson
|
|
|
|
|
|
|
|
|
|
/s/ Josiah O. Low, III
|
|
Director
|
|
February
27, 2009
|
Josiah
O. Low, III
|
|
|
|
|
|
|
|
|
|
/s/ Donald D. Patteson, Jr.
|
|
Director
|
|
February
27, 2009
|
Donald
D. Patteson, Jr.
|
|
|
|
|
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
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Description
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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)).
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Amended
and Restated Bylaws (incorporated herein by reference to Exhibit 3.2 to
the Company’s Current Report on Form 8-K filed on December 10, 2008
(Registration No. 000-51801)).
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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)).
|
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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)).
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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)).
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Settlement
Agreement and Amendment with Calpine Corporation attached hereto as
Exhibit 10.3.
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Amended
and Restated Base Contract for Sale and Purchase of Natural Gas with
Calpine Energy Services, L.P. attached hereto as Exhibit
10.4.
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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)).
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Amended
and Restated 2005 Long-Term Incentive Plan attached hereto as Exhibit
10.9.
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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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)).
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Second
Amendment to Senior Revolving Credit Agreement attached hereto as Exhibit
10.27.
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Second
Amendment to Second Lien Term Loan Agreement attached hereto as Exhibit
10.28.
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Third
Amendment to Senior Revolving Credit Agreement attached hereto as Exhibit
10.29.
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Third
Amendment to Second Lien Term Loan Agreement attached hereto as Exhibit
10.30.
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Amended
and Restated Employment Agreement with Randy L. Limbacher
attached hereto as Exhibit 10.31.
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Amended
and Restated Employment Agreement with Michael J. Rosinski attached hereto
as Exhibit 10.32.
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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).
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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).
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Marketing
and Related Services Agreement with Calpine Natural Gas Services, L.P.
(incorporated herein by reference to Exhibit 10.5 to Form 10-Q filed
November 9, 2007).
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Indemnification
Agreement with Directors and Officers attached hereto as Exhibit
10.36.
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Amended and
Restated Employment Agreement with Michael H. Hickey attached
hereto as Exhibit 10.37.
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Amended
and Restated Employment Agreement with Edward E. Seeman (incorporated
herein by reference to Exhibit 10.38 to Form 10-K filed February 29,
2008).
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2005
Long-Term Incentive Plan Performance Share Unit Award Agreement attached
hereto as Exhibit 10.39.
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Executive
Employee Change of Control Plan attached hereto as Exhibit
10.40.
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Executive
Employee Severance Plan attached hereto as Exhibit
10.41.
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Fourth
Amendment to Senior Revolving Credit Agreement (incorporated herein by
reference to Exhibit 10.42 to Form 10-Q filed August 8,
2008).
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Fourth
Amendment to Second Lien Term Loan Agreement(incorporated herein by
reference to Exhibit 10.43 to Form 10-Q filed August 8,
2008).
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Subsidiaries
of the registrant
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Consent
of PricewaterhouseCoopers LLP
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Consent
of Netherland, Sewell & Associates, Inc.
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Certification
of Periodic Financial Reports by Chief Executive Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
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Certification
of Periodic Financial Reports by Chief Financial Officer in satisfaction
of Section 302 of the Sarbanes-Oxley Act of 2002.
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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.
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___________________________________
†
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Management
contract or compensatory plan or arrangement required to be filed as an
exhibit hereto.
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