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Rosehill Resources Inc. 10-K 2009
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

£
Transition Report Pursuant To Section 13 Or 15(d) of The Securities Exchange Act of 1934
 

 
Commission File Number: 000-51801
                                                                                                                                                     


ROSETTA RESOURCES INC.
(Exact name of registrant as specified in its charter)
 
Delaware
43-2083519
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)
   
717 Texas, Suite 2800, Houston, TX
77002
(Address of principal executive offices)
(Zip Code)
   
Registrant's telephone number, including area code: (713) 335-4000



Securities Registered Pursuant to Section 12(b) of the Act:
 
The Nasdaq Stock Market LLC
Common Stock, $.001 Par Value
(Nasdaq Global Select Market)
(Title of Class)
(Name of Exchange on which registered)

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. 
 


 
 
Large accelerated filer S
 
Accelerated filer £
 
         
 
Non-Accelerated filer £
 
Smaller Reporting Company £ 
 
         
 
(Do not check if a smaller reporting company)
 

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.


 
 
Table of Contents
 
     
     
Part I –
Page
 
4
 
13
 
21
 
21
 
21
 
22
Part II –
 
 
23
 
24
 
25
 
40
 
42
 
71
 
71
 
71
Part III –
 
 
72
 
72
 
72
 
72
 
72
Part IV –
 
 
73
 
 
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
 
Item 1. Business
 
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.

 
 
 
 
 
 
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:

 

 
 
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.
 
Item 1A. Risk Factors

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;
 
 
Consumer demand;
 
 
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;
 
 
Variations in levels of production; and
 
 
The completion of exploration and production projects.
 
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:
 
 
Lack of acceptable prospective acreage;
 
 
Inadequate capital resources;
 
 
Weather conditions and natural disasters;
 
 
Title problems;
 
 
Compliance with governmental regulations;

 
 
Mechanical difficulties; and
 
 
Unavailability or high cost of equipment, drilling rigs, supplies or services.
 
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:
 
 
Unexpected drilling conditions; pressure or irregularities in formations; equipment failures or accidents;
 
 
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;
 
 
Reductions in oil and natural gas prices; and
 
 
Limitations in the market for oil and natural gas.
 
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:
 
 
Well blowouts;
 
 
Cratering;
 
 
Explosions;
 
 
Uncontrollable flows of oil, natural gas, or well fluids;
 
 
Fires;

 
 
Hurricanes, tropical storms, earthquakes, mud slides, and flooding;

 
Pollution; and

 
Releases of toxic gas.

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:
 
 
Division of management’s attention;

 
Ability or impediments to conducting thorough due diligence activities;
 
 
The need to integrate acquired operations;
 
 
Potential loss of key employees of the acquired companies;
 
 
Potential lack of operating experience in a geographic market of the acquired business; and
 
 
An increase in our expenses and working capital requirements.
 
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:
 
 
Adverse weather conditions and natural disasters;

 
Availability of required performance bonds and insurance;
 
 
Oil field service costs and availability;
 
 
Compliance with environmental and other laws and regulations;
 
 
Remediation and other costs resulting from oil spills or releases of hazardous materials; and
 
 
Failure of equipment or facilities.

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
 
Item 2. Properties
 
A description of our properties is located in Item 1. Business and is incorporated herein by reference.
 
Our headquarters are located at 717 Texas, Suite 2800, Houston, Texas 77002, where we sublease two floors of office space from Calpine 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

Graph
 
   
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.
 

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.

 
 
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.
 
 

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;
 
reserve levels;
 
inflation;
 
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;