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EX-21.1 - EXHIBIT 21.1 - Rosetta Resources Inc.ex21_1.htm
EX-23.2 - EXHIBIT 23.2 - Rosetta Resources Inc.ex23_2.htm
EX-23.1 - EXHIBIT 23.1 - Rosetta Resources Inc.ex23_1.htm
EX-31.2 - EXHIBIT 31.2 - Rosetta Resources Inc.ex31_2.htm
EX-31.1 - EXHIBIT 31.1 - Rosetta Resources Inc.ex31_1.htm
EX-99.1 - EXHIBIT 99.1 - Rosetta Resources Inc.ex99_1.htm
EX-32.1 - EXHIBIT 32.1 - Rosetta Resources Inc.ex32_1.htm
EX-10.9 - EXHIBIT 10.9 - Rosetta Resources Inc.ex10_9.htm
EX-10.48 - EXHIBIT 10.48 - Rosetta Resources Inc.ex10_48.htm
EX-10.49 - EXHIBIT 10.49 - Rosetta Resources Inc.ex10_49.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549



FORM 10-K

x
Annual Report Pursuant To Section 13 or 15(d) of the Securities Exchange Act of 1934

For The Fiscal Year Ended December 31, 2010

OR

o
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 x  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes o  No o

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



 
1

 
 
Part III of this Form 10-K or any amendment to this Form 10-K. o

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 x
 
Accelerated filer o
     
Non-Accelerated filer o
 
Smaller Reporting Company o
     
(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 o No x

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2010 was approximately $1.0 billion based on the closing price of $19.81 per share on the Nasdaq Global Select Market.

The number of shares of the registrant’s Common Stock, $.001 par value per share, outstanding as of February 18, 2011 was 52,879,723.

Documents Incorporated By Reference

Portions of the definitive proxy statement relating to the 2011 annual meeting of stockholders to be filed with the Securities and Exchange Commission are incorporated by reference in answer to Part III of this Form 10-K.

 
2

 
 

 
Part I –
Page
 
4
 
14
 
22
 
22
 
22
Part II –
 
 
22
 
24
 
24
 
39
 
42
 
76
 
76
 
77
Part III –
 
 
77
 
77
 
77
 
77
 
77
Part IV –
 
 
78

 
CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Form 10-K contains forward-looking statements regarding factors that we believe may affect our performance in the future. Such statements typically are identified by terms expressing our future expectations or projections of revenues, earnings, earnings per share, cash flow, market share, capital expenditures, effects of operating initiatives, gross profit margin, debt levels, interest costs, tax benefits and other financial items. All forward-looking statements 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 “Risk Factors” in Item 1A 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 80.

Part I

Items 1 and 2. Business and Properties

General

We are an independent exploration and production company engaged in the exploration, development, production and acquisition of onshore oil and gas resources in the United States of America. Our operations are concentrated in South Texas, including our largest producing area in the Eagle Ford shale, the Sacramento Basin of California, and the Rockies, including the Southern Alberta Basin in Montana. Our headquarters are located at 717 Texas, Suite 2800, Houston, Texas 77002. We also have field offices in Laredo and Catarina, Texas, Rio Vista, California and Wray, Colorado.
 
Rosetta Resources Inc. (together with its consolidated subsidiaries, “we,” “our,” “us,” the “Company” or “Rosetta”) was incorporated in Delaware in June 2005 to acquire the domestic oil and natural gas business formerly owned by Calpine Corporation and its affiliates (“Calpine”).   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 and strategically divesting certain non-core properties.  We operate in one business segment.  See Item 8. “Financial Statements and Supplementary Data, Note 15 - Operating Segments.”

We sell most of our California gas to Calpine pursuant to certain gas purchase and sales contracts, including 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. These original gas purchase and sales contracts and the amended and restated gas purchase and sales contract for the dedicated California production are discussed further under Part I. Items 1 and 2. “Business and Properties - Marketing and Customers.”

Our Strategy

Our strategy is to increase stockholder value by delivering visible and sustainable growth from unconventional onshore domestic basins.  This approach is consistent with our strategy to become a successful unconventional resource player with sufficient project inventory to drive significant growth.  We recognize that there may be market cycles that could impact our ability to fully execute our strategy on a short-term basis.  However, we believe our plan is fundamentally sound and emphasizes (i) developing our high return inventory in the Eagle Ford shale in South Texas, (ii) establishing and testing positions in emerging resource plays, (iii) divesting lower return assets to fund and accelerate our unconventional resource initiatives, (iv) applying technological expertise, (v) focusing on cost control and (vi) maintaining financial flexibility.  We seek to implement our strategy while increasing stockholder value through sound stewardship, wise capital resource management, taking advantage of business cycles and emerging trends and minimizing liabilities through governmental compliance and protecting the environment.  Below is a discussion of the key elements of our strategy.

Develop Our High Return Inventory in the Eagle Ford Shale.  During 2010, Rosetta successfully delineated Gates Ranch comprised of approximately 26,500 acres in the liquids-rich portion of the Eagle Ford shale in South Texas. In addition, the Company is continuing to successfully explore other areas of its approximate 65,000 acre leasehold position.  During 2010, the Eagle Ford shale became the largest producing area for Rosetta.  Approximately 53% of the production from this area is comprised of oil, condensate and natural gas liquids (“NGLs”).  In the currently weak natural gas market, the Company’s extensive inventory of investment opportunities in the Eagle Ford shale provides higher economic returns than other opportunities in areas previously considered core to the Company’s operations.  We expect that the Eagle Ford shale will be a major source of production and reserves for the Company in the future and reflects the success of its transition to an unconventional resources player.

Establish and Test Positions in Emerging Resource Plays.  We intend to extend our operational footprint into new core areas within the United States characterized by a significant presence of resource potential that can be exploited utilizing our technological expertise.  We strive to minimize the cost of entry into these plays through financial discipline in our leasehold acquisition activities and prudent management of financial and operational resources during the testing phase.

 
Divest Lower Return Assets to Fund and Accelerate Our Unconventional Resource Initiatives. In the last two years, Rosetta has established a competitive operating presence in the Eagle Ford shale, one of the most active shale basins in the United States that offers a growing inventory of drilling locations with attractive economics.  As a result, we are streamlining our operations and redirecting the proceeds from divestitures of assets that we believe have limited future potential and are no longer core to our long-term growth.  In 2010, property sales totaled approximately $90 million.  Additional divestitures are planned for 2011.

Apply Technological Expertise. We intend to maintain, further develop and apply the technological expertise that helped us achieve a net drilling success rate of 98% for the year ended December 31, 2010 and helped us establish a major new production base in the Eagle Ford shale.   Our definition of drilling success is a well that is producing or capable of production, including wells awaiting pipeline connections to commence deliveries or awaiting connection to production facilities. We use advanced geological and geophysical technologies, detailed petrophysical analyses, advanced reservoir engineering and sophisticated drilling, completion and stimulation techniques to grow our reserves, production and project inventory.

Focus on Cost Control. We manage all elements of our cost structure, including drilling and operating costs as well as overhead costs. We strive to minimize our drilling and operating costs by concentrating our activities within existing and new unconventional resource play areas where we can achieve efficiencies through economies of scale. As part of our strategy to minimize costs, we have taken aggressive steps to ensure access to transportation and processing facilities and oil field services, specifically within the Eagle Ford shale.

Maintain Financial Flexibility. As of December 31, 2010, we had drawn $130.0 million and had $195.0 million available for borrowing under our revolving credit facility. Additionally, we expect internally generated cash flow and proceeds from asset sales to provide additional financial flexibility to further develop our core assets in the next few years.  We intend to continue to actively manage our exposure to commodity price risk in the marketing of our NGLs, crude oil and natural gas production.  As part of this strategy, we have entered into a series of hedging arrangements for each year through 2012.
 
Our Strengths

Our business strategy is to be a successful resource player delivering continued growth and enhanced shareholder value. We believe the following key strengths will enable us to achieve that strategy.

Early Entry and Highly Competitive Position in the Eagle Ford Shale. We hold an asset position in the Eagle Ford shale that we believe will provide the foundation for future growth. As of December 31, 2010, the Company had a 65,000 acre leasehold position with approximately 78% lying in the liquids-rich area of the Eagle Ford shale.  Mineral leases were primarily obtained between 2007 and 2010 at a highly competitive average price of approximately $1,036 per acre.  For the year ended December 31, 2010, approximately 53% of the Company’s production from the area was comprised of oil, condensate and NGLs, which reduced the Company’s exposure to currently low natural gas prices.
 
Resource Assessment Capability and Inventory Generation. We have established multi-disciplinary teams that are skilled at conducting comprehensive resource assessments on a field and regional basis.  This work helps us to indentify and catalog an inventory of low to moderate risk opportunities that provide us with multiple years of drilling projects.  We expect to continue to add to our diversified portfolio of non-proved project inventory from our emerging unconventional resource plays.

Operational Control. We operate approximately 99% of our estimated proved reserves, which allows us to more effectively manage expenses and control the timing of capital spending on our exploration and development operations. 
 
Experienced Management and Technical Team. Our executive management team averages 31 years of service in the energy industry and has a broad knowledge of the exploration and production business with specific expertise in the areas where we are operate.  With the transition to an unconventional resource player, Rosetta recruited additional management and technical talent with previous experience in finding and developing unconventional resources.  This collective ability is a competitive advantage in the execution of our business strategy.

 
Our Operating Areas

We own producing and non-producing oil and gas properties in proven or prospective basins that are primarily located in South Texas, including our largest producing area in the Eagle Ford shale, the Sacramento Basin of California, and the Rockies, including the Southern Alberta Basin in Montana.   For the year ended December 31, 2010, we drilled 127 gross and 124 net wells, with a net success rate of 98%.  The following is a summary of our major operating areas.

South Texas
 
As of December 31, 2010, we owned approximately 178,000 net acres in South Texas.  Our production in South Texas comes from the Eagle Ford shale trend and the Lobo and Olmos fields and averaged 76.3 MMcfe/d for the year ended December 31, 2010, an increase of approximately 28% from the prior year. In 2010, our production from properties outside the Eagle Ford shale averaged 38.0 MMcfe/d, which was 34% below the prior year, reflecting our decision to divert capital away from natural gas producing areas due to low prices to our higher return delineation and development program in the Eagle Ford shale.

Eagle Ford Shale Trend.   In only one year, the Eagle Ford shale trend where we hold approximately 65,000 acres, with 50,000 acres located in the liquids-rich area of the play, has become the largest producing area in our portfolio.  Our first delineation program in the 26,500 acre Gates Ranch located on the county line between Webb and Dimmit Counties was a geologic and commercial success.  In 2010, we drilled 29 gross wells in the Eagle Ford shale, all of which were successful.  Our production from the Eagle Ford shale averaged 38.3 MMcfe/d for the year ended December 31, 2010, with approximately 53% of production comprised of oil, condensate and NGLs. During 2010, we also began an exploratory effort in the Light Ranch portion of the Eagle Ford shale in Central Dimmit County. The first well drilled was a discovery.
 
Lobo Trend.  We are a significant producer in the South Texas Lobo trend, with 470 square miles of 3-D seismic and 249 operated producing wells.  Our working interests range from 50% to 100%, but most of our acreage is 100% owned and operated.   For the year ended December 31, 2010, our average net daily production from the Lobo trend was 27.8 MMcfe/d.

Discovered in 1973, the South Texas Lobo trend is a complex, highly faulted sand that has produced over 8 Tcf of natural gas. The Lobo trend produces from tight sands with low permeability and high pressures at depths from 7,500 to 10,000 feet.

Olmos Trend.  We acquired a 70% non-operated working interest in 231 gross wells in the Olmos trend of South Texas in late 2008.  In 2010, we acquired the remaining 30% working interest and obtained operatorship of these wells.  Production from these wells averaged 4.1 MMcfe/d for the year ended December 31, 2010.

California
 
Historically, the Sacramento Basin has been 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, 2010, we had under lease approximately 54,000 net acres in the Rio Vista Field and other fields in the Sacramento Basin area and our average net daily production from this area was 37.7 MMcfe/d. As part of our strategic decision to focus on the Eagle Ford shale, we entered into an aggrement to sell  our Sacramento Basin assets on February 24, 2011.  See “Recent Developments” below.
 
We have announced our intention to sell our position in California as part of our strategic shift to a resource player with a more balanced mix of NGLs, crude oil and natural gas production.
 
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 in excess of 3.5 Tcfe of natural gas reserves since its discovery in 1936. We currently produce from multiple zones at depths ranging from 2,000 feet to 11,000 feet in the field. The current productive area is approximately ten miles long and nine miles wide.

 
Rockies

Since its formation in 2005, Rosetta has produced from three basins in the Rocky Mountains: the DJ Basin in Colorado, San Juan Basin in New Mexico and Greater Green River Basin in Wyoming. During 2010, we produced 18.4 MMcfe/d from these properties.  In 2010, we made a strategic decision to divest of our interests in New Mexico and Wyoming in order to focus on the development of the Eagle Ford shale and we completed a divestiture of these interests on December 3, 2010.  In 2010, we continued our exploratory initiative in the Southern Alberta Basin in Montana. The play is a westward analog of the industry’s Bakken and Three Forks plays of the Williston Basin of Montana and North Dakota.  We now control approximately 300,000 net acres in the play, either through option or lease agreements.

DJ Basin, Colorado. As of December 31, 2010, we owned a majority working interest in approximately 69,000 net acres with 160 square miles of 3-D seismic data.   For the year ended December 31, 2010, our average net daily production from the DJ Basin was 9.0 MMcfe/d and we drilled 89 gross wells with a 99% success rate. As part of our strategy to further develop the Eagle Ford shale, we entered into an agreement to sell our DJ Basin assets on February 22, 2011.  See “Recent Developments” below.
 
Southern Alberta Basin, Montana.   During late 2009 and in the first half of 2010, three exploratory wells were drilled to test the potential of this emerging Devonian shale play.  Based on the results from these wells, we launched an eight-well vertical drilling program to further understand the reservoir properties and extent of the play across our leasehold position.  As of December 31, 2010, we had drilled six wells. Our evaluations continue and we remain fully committed to testing our holdings in this area where we were an early entrant and hold a competitive position.
 
Recent Developments

As part of our strategic decision to focus on the development of the Eagle Ford shale, we executed a purchase and sale agreement for $55.0 million on February 22, 2011 for the divestiture of our DJ Basin assets in Colorado. This agreement is subject to due diligence and other termination rights and will be subject to post-closing adjustments.  We expect this transaction to close in the second quarter of 2011.

We also executed a purchase and sale agreement with Vintage Petroleum, LLC, for $200.0 million on February 24, 2011 for the divestiture of our Sacramento Basin assets in California.  This agreement is subject to due diligence and other termination rights and will be subject to post-closing adjustments.  We expect this transaction to close in the second quarter of 2011.
  
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 generally have 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.

Crude Oil and Natural Gas Operations

Production by Operating Area

The following tables present certain information with respect to our production data for the periods presented:

   
For the Year Ended December 31, 2010
 
   
Natural Gas
(Bcf)
   
NGLs
(MBbls)
   
Oil
(MBbls)
   
Equivalents
(Bcfe) (1)
 
Eagle Ford
    6.6       690.0       536.0       14.0  
South Texas
    11.2       381.0       68.0       13.8  
California
    13.6       -       27.0       13.8  
Rockies
    6.6       1.0       21.0       6.7  
Gulf Coast
    0.5       15.0       47.0       0.9  
Other Onshore
    0.7       9.0       39.0       1.0  
Total
    39.2       1,096.0       738.0       50.2  

 
   
For the Year Ended December 31, 2009
 
   
Natural Gas
(Bcf)
   
NGLs
(MBbls)
   
Oil
(MBbls)
   
Equivalents
(Bcfe) (1)
 
Eagle Ford
    0.4       12.0       9.0       0.5  
South Texas
    17.2       549.1       121.9       21.3  
California
    15.3       -       28.0       15.5  
Rockies
    6.8       -       20.0       6.9  
Gulf Coast
    3.3       38.0       135.0       4.3  
Other Onshore
    1.5       21.0       80.0       2.1  
Total
    44.5       620.1       393.9       50.6  
                                 
                                 
                                 
   
For the Year Ended December 31, 2008
 
   
Natural Gas
(Bcf)
   
NGLs
(MBbls)
   
Oil
(MBbls)
   
Equivalents
(Bcfe) (1)
 
Eagle Ford
    -       -       -       -  
South Texas
    18.8       257.8       148.0       21.3  
California
    15.8       -       31.0       16.0  
Rockies
    4.5       -       6.0       4.5  
Gulf Coast
    6.3       158.0       247.4       8.7  
Other Onshore
    2.3       25.0       114.0       3.1  
Total
    47.7       440.8       546.4       53.6  


 
(1)
Gas equivalents are determined under the relative energy content method by using the ratio of 1.0 Bbl of oil or natural gas liquid to 6.0 Mcf of gas.

For additional information regarding our oil and gas production, production prices and production costs, see Item 7.  “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Proved Reserves

There are a number of uncertainties inherent in estimating quantities of proved reserves, including many factors beyond our control, such as commodity pricing. Therefore, the reserve information in this report represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers may vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revising the original estimate. Accordingly, initial reserve estimates are often different from the quantities of oil and natural gas that are ultimately recovered. The meaningfulness of such estimates depends primarily on the accuracy of the assumptions upon which they were based. Except to the extent that we acquire additional properties containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as reserves are produced.

As of December 31, 2010, we had an estimated 479.3 Bcfe of proved reserves, including 288.9 Bcf of natural gas, 12,401 MBbls of oil and condensate and 19,326 MBbls of NGLs, of which 51% was proved developed.  As of December 31, 2010 and based on the 2010 twelve-month first day of the month historical average prices as adjusted for basis and quality differentials for West Texas Intermediate oil of $75.96 per Bbl and Henry Hub natural gas of $4.38 per MMBtu, our reserves had an estimated standardized measure of discounted future net cash flows of $697 million.

The following table sets forth, by operating area, a summary of our estimated net proved reserve information as of December 31, 2010:

   
Estimated Proved Reserves at December 31, 2010 (1)(2)
 
   
Developed
   
Undeveloped
         
Percent of
 
   
Natural Gas
(Bcf)
   
NGLs
(MMBbls)
   
Oil
(MMBbls)
   
Total
(Bcfe) (3)
   
Natural Gas
(Bcf)
   
NGLs
(MMBbls)
   
Oil
(MMBbls)
   
Total
(Bcfe) (3)
   
Total
(Bcfe) (3)
   
Total
Reserves
 
Eagle Ford
    39.92       4.26       3.26       85.03       102.84       12.85       8.71       232.25       317.3       66 %
South Texas
    60.85       2.21       0.32       76.01       -       -       -       -       76.0       16 %
California
    42.09       -       0.04       42.32       -       -       -       -       42.3       9 %
Rockies
    40.29       -       0.05       40.62       2.13       -       -       2.13       42.8       9 %
Gulf Coast
    0.51       0.01       0.01       0.62       -       -       -       -       0.6       0 %
Other Onshore
    0.29       -       -       0.29       -       -       -       -       0.3       0 %
Total
    183.95       6.48       3.68       244.89       104.97       12.85       8.71       234.38       479.3       100 %

___________________________________
 
(1)
These estimates are based upon a reserve report prepared using internally developed reserve estimates and criteria in compliance with the SEC guidelines and audited by Netherland, Sewell & Associates, Inc. (“NSAI”), independent petroleum engineers.  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.”  NSAI’s report is attached as Exhibit 99.1 to this Form 10-K.

 
(2)
The reserve volumes and values were determined under the method prescribed by the SEC, which requires the use of an average price, calculated as the twelve-month first day of the month historical average price for the twelve-month period prior to the end of the reporting period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
 
 
(3)
Gas equivalents are determined under the relative energy content method by using the ratio of 1.0 Bbl of oil or natural gas liquid to 6.0 Mcf of gas.
 
All of our proved undeveloped reserves at December 31, 2010 are scheduled for development within five years from the date recorded as a proved undeveloped reserve.

As of December 31, 2010, we had proved undeveloped reserves of 234.4 Bcfe, an increase of 148.0 Bcfe relative to December 31, 2009.  Significant additions of proved undeveloped reserves resulted primarily from additional proved undeveloped locations in our Eagle Ford shale acreage. Approximately $22.6 million was spent in 2010 associated with the development of 10.3 Bcfe of proved undeveloped reserves.  The 10.3 Bcfe includes positive performance revisions of 4.0 Bcfe due to better than expected performance in the Eagle Ford shale.  Of the $22.6 million, $18.9 million is related to the Company’s development in the Eagle Ford shale that resulted in the development of 9.1 Bcfe (including positive performance revisions).
 
In accordance with SEC guidelines, the reserve engineers’ estimates of future net revenues from our properties, and the present value of the properties, are made using the twelve-month first day of the month historical average oil and gas prices for the December 31, 2010 reserves and oil and gas sales prices in effect as of the end of the period of such estimates for prior periods, and are held constant throughout the life of the properties, except where the guidelines permit alternate treatment, including the use of fixed and determinable contractual price escalations.  Historically, the prices for oil and gas have been volatile and are likely to continue to be volatile in the future.

Internal Control

The preparation of our reserve estimates are in accordance with our prescribed internal control procedures, which include verification of input data into a reserve forecasting and economic evaluation software, as well as management review.  The internal controls include but are not limited to the following:

 
A comparison of historical expenses is made to the lease operating costs in the reserve database.

 
Updated capital costs are supplied by Rosetta’s Operations Department.

 
Internal reserves estimates are reviewed by well and by area by the Corporate Engineering Manager.  A variance by well to the previous year-end reserve report and quarter-end reserve estimate is used as a tool in this process.

 
Material reserve variances are discussed among the internal reservoir engineers and the Corporate Engineering Manager to insure the best estimate of remaining reserves.

 
The internal reserves estimates are reviewed by senior management prior to publication.

The Company’s primary reserves estimator is Mark D. Petrichuk, Corporate Engineering Manager.  Mr. Petrichuk has 33 years of experience in the petroleum industry spent almost entirely in the evaluation of reserves and income attributable to oil and gas properties. He holds a Bachelor of Science in Mechanical Engineering from Texas A&M University. He is a licensed Professional Engineer in the State of Texas and is a member of the Society of Petroleum Engineers. The Corporate Engineering Manager maintains oversight and compliance responsibility for the internal reserve estimate process and provides appropriate data to and oversees the independent third party engineers for the annual audit of our year-end reserves.

Qualifications of Third Party Engineers

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies.  NSAI was founded in 1961 and performs consulting petroleum engineering services under the Texas Board of Professional Engineers Registration No. F-002699.  Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit incorporated herein are Mr. Danny Simmons and Mr. David Nice.  Mr. Simmons has been a practicing consulting petroleum engineer at NSAI since 1976.  Mr. Simmons is a Registered Professional Engineer in the State of Texas (License No. 45270) and has over 38 years of practical experience in petroleum engineering, with over 35 years experience in the estimation and evaluation of reserves.  He graduated from the University of Tennessee in 1973 with a Bachelor of Science Degree in Mechanical Engineering.  Mr. Nice has been a practicing consulting petroleum geologist at NSAI since 1998.  Mr. Nice is a Certified Petroleum Geologist and Geophysicist in the State of Texas (License No. 346) and has over 26 years of practical experience in petroleum geosciences, with over 12 years experience in the estimation and evaluation of reserves.  He graduated from the University of Wyoming in 1982 with a Bachelor of Science Degree in Geology and in 1985 with a Master of Science Degree in Geophysics.  Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

 
2010 Capital Expenditures

The following table summarizes information regarding our development and exploration capital expenditures for the years ended December 31, 2010, 2009 and 2008:

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(In thousands)
 
                   
Capital expenditures
  $ 268,578     $ 90,524     $ 197,026  
Leasehold
    49,328       22,066       57,261  
Acquisitions
    5,986       3,624       62,570  
Delay rentals
    1,193       1,683       1,451  
Geological and geophysical/seismic
    518       8,558       4,571  
Exploration overhead
    7,775       4,806       7,140  
Capitalized interest
    4,017       1,174       1,422  
Other corporate
    2,042       2,942       3,046  
Total capital expenditures
  $ 339,437     $ 135,377     $ 334,487  


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, 2010.  “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.

                           
Productive Wells
 
   
Undeveloped Acres
   
Developed Acres
   
Gross
   
Net
 
   
Gross
   
Net
   
Gross
   
Net
   
Natural Gas
   
Oil
   
Natural Gas
   
Oil
 
Eagle Ford
    104,951       62,875       2,310       2,284       22       -       21       -  
South Texas
    41,325       36,435       67,606       66,042       431       2       400       2  
California
    16,875       9,463       53,504       44,188       140       -       131       -  
Rockies (1)
    148,870       135,593       20,490       18,156       208       2       205       1  
Gulf Coast
    5,000       2,500       12,532       5,660       1       -       -       -  
Other Onshore
    2,904       1,341       -       -       9       1       3       -  
Total
    319,925       248,207       156,442       136,330       811       5       760       3  


 
(1)
Excludes approximately 228,000 net undeveloped acres under exploration option in the Southern Alberta Basin.

Of our productive wells listed above, there were nine and ten multiple completions in Texas and California, respectively.

The following table shows our interest in undeveloped acreage as of December 31, 2010 that is subject to expiration in 2011, 2012, 2013 and thereafter:

2011
   
2012
   
2013
   
Thereafter
 
Gross
 
Net
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
77,684
    66,722       48,037       40,525       15,854       19,649       134,975       120,403  


Drilling Activity

The following table sets forth the number of gross exploratory and development wells we drilled or in which we participated during the last three fiscal years. The number of wells drilled refers to the number of wells completed at any time during the respective fiscal year.  Productive wells are either producing wells or wells capable of production.

 
 
   
Exploratory
   
Development
 
   
Productive
   
Dry
   
Total
   
Productive
   
Dry
   
Total
 
2010
    10.0       -       10.0       115.0       2.0       117.0  
2009
    7.0       -       7.0       30.0       6.0       36.0  
2008
    3.0       1.0       4.0       160.0       20.0       180.0  

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
 
2010
    9.9       -       9.9       112.4       2.0       114.4  
2009
    6.1       -       6.1       23.4       6.0       29.4  
2008
    1.9       1.0       2.9       132.7       15.9       148.6  
 
At December 31, 2010, we had two wells in process.  These wells were located in the South Texas Eagle Ford shale where we owned a 90% working interest in one well and a 100% working interest in the remaining well.

Marketing and Customers

We have entered into a natural gas purchase and sales contract with Calpine Energy Services (“CES”) for the dedicated California production, which runs through December 2019.  Under the terms of this agreement, we are obligated to sell all our existing and future production from our California leases in production as of May 1, 2005 based on market prices.   For the year ended December 31, 2010, natural gas sales from dedicated production comprised approximately 35% of our overall natural gas sales for the Company.

Under the terms of the purchase and sales contract with CES, cash payment for all natural gas volumes that are contractually sold to CES on the previous day is deposited into our 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 may market our remaining natural gas production in California to parties other than CES.  All of our other production (other than our dedicated California production being sold to CES, as described above) is sold to various purchasers, including CES, at market rates.  We market all of our oil and gas production and have expanded our internal capabilities in this regard, both by hiring experienced personnel and implementing our own licensed systems.

Major Customers

For the year ended December 31, 2010, we had two major customers, CES and Shell Trading (US) Company, which accounted for approximately 48% and 16%, respectively, 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 resulting 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, producing or marketing 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.
 
Government Regulation
 
 The oil and gas industry is subject to extensive laws that are subject to change.  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 we 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 the location, 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 Regulation
 
General.  Our operations are subject to extensive environmental, health and safety regulation by federal, state and local agencies.  These requirements govern the handling, generation, storage and management of hazardous substances, including how these substances are released or discharged into the air, water, surface and subsurface. These laws and regulations often require permits and approvals from various agencies before we can commence or modify our operations or facilities and on occasion (especially on federally-managed land) require the preparation of an environmental impact assessment or study (which can result in the imposition of various conditions and mitigation measures) prior to or in connection with obtaining such permits.  In connection with releases of hydrocarbons or hazardous substances into the environment, we may be responsible for the costs of remediation even if we did not cause the release or were not otherwise at fault, under applicable laws.  These costs can be substantial and we evaluate them regularly as part of our environmental and asset retirement programs.  Failure to comply with applicable laws, permits or regulations can result in project or operational delays, civil or in some cases criminal fines and penalties and remedial obligations.

Sacramento and San Joaquin Rivers Delta.  In November 2009, the California State legislature enacted a package of four bills, which the governor signed, and introduced an $11.14 billion bond measure to be voted on by the California voters in the November 2012 election.  These bills promise to restore and maintain the delta resulting from the confluence of the Sacramento and San Joaquin rivers, while simultaneously sending needed water to the farmers in the western San Joaquin Valley and to urban and farming water users to the south.  The Company currently produces about one third of its natural gas in this delta. We are involved in monitoring and providing comments to the anticipated plans, rules and regulations to be proposed by the State committees responsible for implementing this legislation.  To the extent that the State elects to proceed with a peripheral canal, certain of the proposed options for the route of such a canal have the potential to impact some of our land and access rights in our Rio Vista Gas Field.  In addition, proposed habitat restoration goals under the regulatory programs may be significant and may include reduced or discontinued maintenance of certain existing levees to allow marshlands to return to their natural state.  As a result, the implementation of this legislation and associated regulatory programs (and any potential peripheral canal) may increase significantly the Company’s costs to maintain certain levees and may affect the Company’s operations in the Rio Vista Gas Field.

Climate Change.  Current and future regulatory initiatives directed at climate change may increase our operating costs and may, in the future, reduce the demand for some of our produced materials. The United States Congress is currently considering legislation on climate change. In September 2009, the U.S. House of Representatives passed a comprehensive clean energy and climate bill (H.R. 2454, also known as “Waxman-Markey”). The U.S. Senate is working on a variety of proposed climate bills, including the American Power Act of 2010 (proposed by Senators Kerry and Lieberman). These bills or new legislation may be considered by the current Congress. In substance, most legislative proposals contain a “cap and trade” approach to greenhouse gas regulation. Under such an approach, companies would be required to hold sufficient emission allowances to cover their greenhouse gas emissions. Over time, the total number of allowances would be reduced or expire, thereby relying on market-based incentives to allocate investment in emission reductions across the economy. As the number of available allowances declines, the cost would presumably increase. In addition to the prospect of federal legislation, several states have adopted or are in the process of adopting greenhouse gas reporting or cap-and-trade programs. Therefore, while the outcome of the federal and state legislative processes is currently uncertain, if such an approach were adopted (either by domestic legislation, international treaty obligation or domestic regulation), we would expect our operating costs to increase as we buy additional allowances or embark on emission reduction programs.

 
Even without further federal legislation, the United States Environmental Protection Agency (“EPA”) has begun to regulate greenhouse gas emissions. In December 2009, the EPA released an Endangerment and Cause or Contribute Findings for Greenhouse Gases, which became effective in January 2010. This regulatory finding sets the foundation for future EPA greenhouse gas regulation under the Clean Air Act. The EPA also promulgated a new greenhouse gas reporting rule, which became effective in December 2009, and which requires facilities that emit more than 25,000 tons per year of carbon dioxide-equivalent emissions to prepare and file certain emission reports. Finally, on November 8, 2010, the EPA adopted rules expanding the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities. These rules require data collection beginning in 2011 and reporting beginning in 2012. Some of our facilities are subject to these rules. On May 12, 2010, the EPA issued a new “tailoring” rule, which proposed and imposes additional permitting requirements on certain stationary sources emitting over 75,000 tons per year of carbon dioxide equivalent emissions. This rule does not currently affect our operations but may as our operations grow. Finally, the EPA is considering additional rulemaking to apply these requirements to broader classes of emission sources by 2012, which may apply to some of our facilities.  As a result of these regulatory initiatives, our operating costs may increase in compliance with these programs, although we are not situated differently in this respect from our competitors in the industry.

Hydraulic Fracturing.  Congress is also considering legislation that would repeal the current exemption in the Safe Drinking Water Act’s underground injection control program for hydraulic fracturing.  We and our competitors use hydraulic fracturing in our operations.  If this legislation is passed, it would impose additional requirements on our hydraulic fracturing operations and we would face additional requirements, including permitting requirements, financial assurances, public disclosure obligations, monitoring and reporting requirements.  Such a result could increase our operating costs.  The disclosure requirements also could increase the possibility of third-party or government legal challenges to hydraulic fracturing.  Even without such legislation, hydraulic fracturing has come under increased regulatory scrutiny in certain locations, such as New York, although our operations have not yet been affected.
 
Wyoming Air Permit.  On February 12, 2010, we received a Notice of Violation (“Notice”) from the Wyoming Department of Environmental Quality (“Wyoming DEQ”) regarding a multiple wellsite facility for wet gas/condensate production and six associated wells located in Sublette County, Wyoming (collectively, the “Wellsite”). The Notice alleged that we did not obtain a construction permit prior to constructing the Wellsite and that we operated the Wellsite in violation of applicable regulations by allegedly having failed to control air emissions from six associated wells. The Notice threatened referral of the matter to the Wyoming Attorney General for “appropriate penalties,” which could have included civil penalties or injunctive relief. In the fourth quarter of 2010, we settled the Wyoming DEQ Notice of Violation for a total of $25,000 and the required permits were obtained.
 
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 material loss not fully covered by insurance could have an adverse effect on our financial position, results of operations or cash flows.  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.  
 
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 2010, we filed estimates of our oil and gas reserves as of December 31, 2009 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, 2009.    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 18, 2011, we had 168 full time employees. We also contract for the services of consultants involved in land, regulatory, accounting, financial, legal and other disciplines, as needed.  None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are satisfactory.
 
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 Securities Exchange Act of 1934, as amended, our proxy statements, 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

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 of 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 a variety of factors beyond our control, such as:
 
 
Domestic and foreign supply of oil and natural gas;
 
 
 
Price and quantity of foreign imports of oil and natural gas;
 
 
 
Actions of the Organization of Petroleum Exporting Countries and state-controlled oil companies relating to oil price and production controls;
 
 
 
Consumer demand;
 
 
 
The impact of energy conservation efforts;
 
 
 
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;

 
The availability of refining capacity;
 
 
 
Weather conditions and natural disasters;

 
Technological advances affecting oil and natural gas production and 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 relation to each other. Our revenue, profitability, and cash flow depend upon the prices of and demand for oil and natural gas, and a drop in prices can significantly affect our financial results and impede our growth.  In particular, declines in commodity prices will:

 
 
Negatively impact the value of our reserves, because declines in oil and natural gas prices would reduce the amount of oil and natural gas that we can produce economically;

 
Reduce the amount of cash flow available for capital expenditures, repayment of indebtedness, and other corporate purposes; and

 
Result in a decrease in the borrowing base under our revolving credit facility or otherwise limit our ability to borrow money or raise additional capital.

Broad industry or economic factors may adversely affect the timing of and extent to which we can effectively implement our strategy as an onshore unconventional resource player.

Several factors could adversely impact our ability to implement our strategy as an onshore unconventional resource player, including: (i) a sustained downturn of commodity prices, (ii) a lack of inventory potential within existing resource plays, (iii) an inability to attract and retain the personnel necessary to implement an unconventional resource business model, and (iv) a lack of access to capital.

Adverse economic and capital market conditions may significantly affect our ability to meet liquidity needs, access to capital and cost of capital.

Fiscal 2008 and 2009 periods were periods of severe volatility and disruption in the economy and capital markets.  While there were signs in 2010 that the economy may be improving, the potential remains for further volatility and disruption.  During 2008 and 2009, the markets produced downward pressure on stock prices and credit capacity for certain issuers without regard to those issuers’ underlying financial strength.  If these levels of market disruption and volatility return, our business, financial condition and results of operations, as well as our ability to access capital, may all be negatively impacted.
 
Potential 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.  Borrowings under our existing revolving credit facility are subject to the maintenance of a borrowing base, which is subject to semi-annual and other adjustments. In the event that our borrowing base is reduced, outstanding borrowings in excess of the revised borrowing base will be due and payable immediately and 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 may require us to reduce our capital expenditures, which may in turn adversely affect our ability to carry out our business plan. 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 leases could have a material adverse effect on our results of operations.

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.  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 sell a significant amount of our production to one customer.

We have a natural gas purchase and sale contract with CES, which runs through December 2019. Under this contract, we are obligated to sell to CES all of our existing and future production from our California leases in production as of May 1, 2005 at market prices.  For the year ended December 31, 2010, natural gas sales from dedicated production comprised approximately 35% of our overall natural gas sales for the Company.   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 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, 2010 would be approximately $1.0 million.

 
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.
 
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 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 and pay dividends on our common stock. We are also required by the terms of our credit facilities to comply with financial covenants.  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 lender 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.

Our revolving credit facility also limits the amounts we can borrow to a borrowing base amount, as determined by the lenders in accordance with the credit agreement.  Outstanding borrowings in excess of the borrowing base will be required to be repaid immediately, or we will be required to pledge other oil and natural gas properties as additional collateral.
 
Our exploration and development activities may not be commercially successful.
 
Exploration and development activities involve numerous risks, including the risk that no commercially productive quantities of oil or natural gas 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:
 
 
Reductions in oil and natural gas prices;

 
Unexpected drilling conditions;

 
Pressure or irregularities in formations;

 
Equipment failures or accidents;
 
 
 
Adverse weather conditions;

 
Compliance with environmental and other governmental regulations;

 
Environmental hazards, such as natural gas leaks, oil spills, pipeline ruptures and discharges of toxic gases;

 
Unavailability or high cost of drilling rigs, equipment or labor;

 
Possible federal, state, regional and municipal regulatory moratoriums on new permits, delays in securing new permits, changes to existing permitting requirements without “grandfathering” of existing permits and possible prohibition and limitations with regard to certain completion activities;

 
Limitations in takeaway capacity or the market for oil and natural gas;

 
Increase in severance taxes; and

 
Lost or damaged oilfield development and services tools.
 
Our decisions to purchase, explore, develop and exploit prospects or properties depend, in part, on data obtained through geological and geophysical analyses, production data and engineering studies, the results of which are uncertain. Even when used and properly interpreted, 3-D seismic data and visualization techniques only assist geoscientists in identifying potentially productive hydrocarbon traps and geohazards. 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 our engineers and audited 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. 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, 2010 were based on the twelve-month first day of the month historical average West Texas Intermediate oil prices adjusted for basis and quality differentials of $75.96 per Bbl and the twelve-month first day of the month historical average Henry Hub gas prices adjusted for basis and quality differentials of $4.38 per MMbtu.  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 Bureau of Ocean Energy Management, Regulation and Enforcement, or "BOE," (formerly known as the Minerals Management Service) of the U.S. Department of the Interior, 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.
 
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 standardized measure 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 the standardized measure of future net cash flows.

We are subject to the full cost ceiling limitation, which has previously resulted in a write-down of our estimated net reserves, and may result in additional write-downs in the future if commodity prices 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 judgment.  The current ceiling calculation utilizes a twelve-month first day of the month historical average price and does not allow for us to re-evaluate the calculation subsequent to the end of the period if prices increase.  It also dictates that costs in effect as of the last day of the quarter are held constant.  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.
 
We recognized a non-cash, pre-tax ceiling test impairment of $205.7 million and $238.7 million in the third and fourth quarters, respectively, of 2008 and of $379.5 million in the first quarter of 2009.  We did not record any write-down or impairment for the year ended December 31, 2010.  Due to the volatility of commodity prices, however, should natural gas prices decline in the future, it is possible that write-downs 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.   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, regional and local laws and regulations. Extensive laws, regulations and rules regulate 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, production levels, royalty obligations, price levels, environmental requirements, and other aspects of our business, including our general profitability. We are unable to predict changes to existing laws and regulations. For example, in response to the April 2010 fire and explosion onboard the semisubmersible drilling rig Deepwater Horizon, leading to the oil spill in the Gulf of Mexico, the BOE has limited certain drilling activities in the U.S. Gulf of Mexico. The BOE may also issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico, and potentially in other geographic regions, and may take other steps that could increase the costs of exploration and production. This incident could also result in drilling suspensions or other regulatory initiatives in other areas of the U.S. and abroad. Furthermore, the U.S. Environmental Protection Agency has recently focused on public concerns about the risk of water contamination and public health problems from drilling and hydraulic fracturing activities.  This renewed focus could lead to additional federal and state regulations affecting the oil and gas industry. Additional regulations or other changes to existing laws and regulations could significantly impact our business, results of operations, cash flows, financial position and future growth.

Our business requires a 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 technical skills could have a negative effect on our business, financial position, results of operations, cash flows and future growth.

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. 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. Our concentration of operations in certain geographic areas, such as the Eagle Ford shale, increases this risk and the potential impact upon us.  When that also occurs, we are unable to realize revenue from those wells until the production can be tied to a pipeline or 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. Our competitors include major and large independent oil and natural gas companies that possess financial, technical and personnel resources substantially greater than our resources. Those companies may be able to develop and acquire more prospects and productive properties at a lower cost and more quickly 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. 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.
 
Our strategy as an onshore unconventional resource player has resulted in operations concentrated in one geographic area and increases our exposure to many of the risks enumerated herein.

Currently our operations are highly concentrated in South Texas, primarily in the Eagle Ford shale. This concentration increases the potential impact that many of the risks stated herein may have upon our ability to perform. For example, we have greater exposure to regulatory actions impacting Texas, natural disasters in the geographic area, competition for equipment, services and materials available in the area and access to infrastructure and markets.
 
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 natural 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 the Eagle Ford shale of Texas, California or the Rockies, 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 (particularly in California), mud slides, and flooding;

 
Pollution; and

 
Releases of toxic gas.

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. We are not fully insured against all risks, including development and completion risks that are generally not recoverable from third parties or insurance. In addition, our insurance policies provide limited coverage for losses or liabilities relating to sudden and accidental pollution, but not for other types of pollution. Our insurance might be inadequate to cover our liabilities.  Our energy package is written on reasonably standard terms and conditions that are generally available to the exploration and production industry. 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 in the future as the insurance industry adjusts to difficult exposures 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 for a risk at a time when we do not have liability insurance, then our business, financial position, results of operations and cash flows could be materially adversely affected.  
 
Competition and regulation of hydraulic fracturing services could impede our ability to develop our shale plays.

The unavailability or high cost of high pressure pumping services (or hydraulic fracturing services), chemicals, proppant, water, and related services and equipment could limit our ability to execute our exploration and development plans on a timely basis and within our budget.  Our industry is experiencing a growing emphasis on the exploitation and development of shale gas and shale oil resource plays which are dependent on hydraulic fracturing for economically successful development.  Hydraulic fracturing in shale plays requires high pressure pumping service crews.  A shortage of service crews or proppant, chemical, or water, especially if this shortage occurred in South Texas or the Rockies, could materially and adversely affect our operations and the timeliness of executing our development plans within our budget.  There is significant regulatory uncertainty as some states have begun to regulate hydraulic fracturing and the United States Environmental Protection Agency and United States Congress are investigating the impact of hydraulic fracturing on drinking water sources, which could affect the current regulatory jurisdiction of the states and increase the cycle times and costs to receive permits, delay or possibly preclude receipt of permits in certain areas, impact water usage and waste water disposal and require chemical additives disclosures.

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.

 
Possible regulations related to global warming and climate change could have an adverse effect on our operations and the demand for oil and natural gas.

Recent scientific studies have suggested that emissions of certain gases, commonly referred to as "greenhouse gases," may be contributing to the warming of the Earth's atmosphere. Methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of refined oil products and natural gas, are examples of greenhouse gases. The U.S. Congress is considering climate-related legislation to reduce emissions of greenhouse gases. In addition, at least 20 states have developed measures to regulate emissions of greenhouse gases, primarily through the planned development of greenhouse gas emissions inventories and/or regional greenhouse gas cap and trade programs. The EPA has adopted regulations requiring reporting of greenhouse gas emissions from certain facilities and is considering additional regulation of greenhouse gases as "air pollutants" under the existing federal Clean Air Act. In November 2010, the EPA adopted rules expanding the industries subject to greenhouse gas reporting to include certain petroleum and natural gas facilities.  These rules require data collection beginning in 2011 and reporting beginning in 2012.  Some of our facilities are subject to these rules. Passage of climate change legislation or other regulatory initiatives by Congress or various states, or the adoption of other regulations by the EPA or analogous state agencies, that regulate or restrict emissions of greenhouse gases (including methane or carbon dioxide) in areas in which we conduct business could have an adverse effect on our operations and the demand for oil and natural gas.

Our property acquisition strategy could fail or present unanticipated problems for our business in the future, which could adversely affect our ability to make property acquisitions or realize anticipated benefits of those acquisitions.

Our growth strategy includes acquiring oil and natural gas properties. 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:
 
 
Diversion of management’s attention;

 
Ability or impediments to conducting thorough due diligence activities;
 
 
 
Potential lack of operating experience in the geographic market where the acquired properties are located;
 
 
 
An increase in our expenses and working capital requirements;
 
 
 
The validity of our assumptions about reserves, future production, revenues, capital expenditures, and operating costs, including synergies;
 
 
 
A decrease in our liquidity by using a significant portion of our available cash or borrowing capacity under our revolving credit facility to finance acquisitions;
 
 
 
A significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
 
 
 
The assumption of unknown liabilities, losses, or costs for which we are not indemnified or for which our indemnity is inadequate; and

 
The incurrence of other significant charges, such as impairment of oil and natural gas properties, asset devaluation, or restructuring charges.

Our decision to acquire a property will depend in part on the evaluation of data obtained from production reports and engineering studies, geophysical and geological analyses, and seismic and other information, the results of which are often inconclusive and subject to various interpretations.

Also, our reviews of acquired properties are inherently incomplete because it generally is not feasible to perform an in-depth review of the individual properties involved in each acquisition given time constraints imposed by sellers.  Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to fully access their deficiencies and potential.  Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken.

 
Hedging transactions may limit our potential revenue, result in financial losses or reduce our income.
 
We have entered into oil, natural gas, and NGL price hedging arrangements with respect to a portion of our expected production through 2012.  These hedging transactions may limit our potential revenue if oil, natural gas, and NGL prices were to rise substantially over the price established by the hedge.  As of December 31, 2010, approximately 88% of total hedged natural gas transactions represented hedged prices of commodities at the PG&E Citygate and Houston Ship Channel, 100% of hedged crude oil transactions represented hedged prices of crude oil at the West Texas Intermediate on the NYMEX and approximately 52% of the total hedged NGL transactions represented hedged NGL prices at Mont Belvieu Propane (Non-TET) OPIS.  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.

The impairment of financial institutions or counterparty credit default could adversely affect us.

Our commodity derivative transactions expose us to credit risk in the event of default by our counterparties that include commercial banks, investment banks, insurance companies, other investment funds and other institutions.  Further 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.  We may have significant exposure to our derivative counterparties and the value of our derivative positions may provide a significant amount of cash flow.  In addition, if any lender under our revolving credit facility is unable to fund its commitment, our liquidity will be reduced by an amount up to the aggregate amount of such lender’s commitment under our revolving credit facility.  Currently, no single lender in our credit facility has commitments representing more than 11% of our total commitments.  However, if banks continue to consolidate, we may experience a more concentrated credit risk.

Federal legislation regarding derivatives could have an adverse effect on our ability and cost of entering into derivative transactions.

On July 21, 2010, the President signed into law the Dodd-Frank Wall Street Reform and Consumer Protection Act (the Dodd-Frank Reform Act), which, among other provisions, establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The new legislation requires the Commodities Futures Trading Commission (the CFTC) and the Securities and Exchange Commission to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. On October 1, 2010, the CFTC introduced its first series of proposed rules coming out of the Dodd-Frank Reform Act. The effect of the proposed rules and any additional regulations on our business is currently uncertain. Of particular concern, the Dodd-Frank Reform Act does not explicitly exempt end users (such as us) from the requirements to post margin in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margin from end users, the exemption is not in the act. The new requirements to be enacted, to the extent applicable to us or our derivatives counterparties, may result in increased costs and cash collateral requirements for the types of derivative instruments we use to hedge and otherwise manage our financial and commercial risks related to fluctuations in natural gas, oil and NGL commodity prices. Any of the foregoing consequences could have a material adverse effect on our consolidated financial position, results of operations and cash flows.

 
Certain federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.

Among the changes contained in the President’s Fiscal Year 2012 budget proposal, released by the White House on February 14, 2011, is the elimination or deferral of certain key U.S. federal income tax deductions currently available to oil and gas exploration and production companies. Such changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties; (ii) the elimination of current deductions for intangible drilling and development costs; (iii) the elimination of the deduction for certain U.S. production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. Recently, members of the U.S. Congress have considered similar changes to the existing federal income tax laws that affect oil and gas exploration and production companies, which, if enacted, would negatively affect our financial condition and results of operations. The passage of any legislation as a result of the budget proposal or any other similar change in U.S. federal income tax law could eliminate or defer certain tax deductions within the industry that are currently available with respect to oil and gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Item 1B. Unresolved Staff Comments
 
None.
 
Item 3. Legal Proceedings

We are party to various legal and regulatory proceedings arising in the ordinary course of business.  The ultimate outcome of each of these matters cannot be absolutely determined, and 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 for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the consolidated financial statements.
 
Item 4. Removed and Reserved

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”.  The following table sets forth the high and low sale prices of our common stock for the periods indicated:

2010
 
2009
 
   
High
   
Low
     
High
   
Low
 
January 1 - March 31
  $ 25.20     $ 17.21  
January 1 - March 31
  $ 8.37     $ 3.52  
April 1 - June 30
    26.92       18.39  
April 1 - June 30
    10.17       4.81  
July 1 - September 30
    24.18       18.77  
July 1 - September 30
    15.60       7.08  
October 1 - December 31
    38.98       23.02  
October 1 - December 31
    20.62       12.35  

The number of shareholders of record on February 18, 2011 was approximately 190. 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 our financial condition, capital requirements, earnings prospects and limitations imposed by our lenders or by any of our investors, as well as other factors the board of directors may deem relevant.  The declaration and payment of dividends is restricted by our existing revolving credit facility, the indenture governing our 9.500% Senior Notes due 2018 (“Senior Notes”), and our existing term loan.  Future agreements may also restrict our ability to pay dividends.
 
The following table sets forth certain information with respect to repurchases of our common stock during the three months ended December 31, 2010:

 
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
    3,054     $ 24.02       -       -  
November 1 - November 30
    21,206       24.03       -       -  
December 1 - December 31
    21,028       36.22       -       -  
 
 
(1)
All of the shares were surrendered by our employees and directors 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, 2010.  As required by applicable rules of the SEC, 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 listing of its common stock on The NASDAQ), and $100 was invested in each of the Standard & Poor’s 500 Index (S&P 500) and the Standard & Poor’s MidCap 400 Oil & Gas Exploration & Production Index (S&P 400 E&P) at the opening price on February 13, 2006.

 
·
All dividends are reinvested for each measurement period.

 
The S&P 400 E&P 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.
 
 
Total Return Among Rosetta Resources Inc., the S&P 500 Index and the S&P 400 O&G E&P Index
 
 
 
   
2/13/2006 (1)
   
12/31/2006
   
12/31/2007
   
12/31/2008
   
12/31/2009
   
12/31/2010
 
ROSE
  $ 100.00     $ 98.26     $ 104.37     $ 37.26     $ 104.84     $ 198.11  
S&P 500
    100.00       113.86       120.12       75.67       95.70       110.12  
S&P 400 E&P
    100.00       103.24       149.13       67.84       120.86       173.08  
 
 
(1)
February 13, 2006 was the first full trading day following the Company’s listing of its common stock on The NASDAQ.

Item 6. Selected Financial Data
 
The following selected financial data should be read 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.
 
   
Year Ended
December 31,
       
   
2010
   
2009 (1)
   
2008 (1)
   
2007
   
2006
 
   
(In thousands, except per share data)
 
Operating Data:
                             
Total revenues
  $ 308,430     $ 293,951     $ 499,347     $ 363,489     $ 271,763  
Net income (loss)
    19,046       (219,176 )     (188,110 )     57,205       44,608  
Net Income (loss) per share:
                                       
Basic
    0.37       (4.30 )     (3.71 )     1.14       0.89  
Diluted
    0.37       (4.30 )     (3.71 )     1.13       0.88  
Cash dividends declared per common share
    -       -       -       -       -  
Balance Sheet Data (At the end of the Period)
                                       
Total assets
    997,309       879,584       1,154,378       1,357,214       1,219,405  
Long-term debt
    350,000       288,742       300,000       245,000       240,000  
Stockholders' equity
    528,816       493,095       726,372       872,955       822,289  


 
(1)
Includes a $379.5 million and a $444.4 million non-cash, pre-tax impairment charge for the years ended December 31, 2009 and 2008, respectively.

We did not declare or pay any cash dividends for any of the periods indicated in the table above.
 
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
During 2010, Rosetta began to realize benefits from its transformation to an unconventional resource player.  Most notably, we built a portfolio of high-quality shale assets with project inventory offering visible and sustainable growth.
 
Our success was the result of the initiative that we began three years ago to employ personnel with the appropriate competencies to execute an unconventional resource-driven business model. We were an early entrant into the Eagle Ford shale, one of the most competitive shale plays in the industry and one of the first participants to develop a significant leasehold position and conduct comprehensive exploratory evaluations in that play.  Our efforts were coupled with a conservative fiscal approach and a focus on cost control and efficiency.

We believe that our 2010 performance as an unconventional resource player as compared to our 2009 performance serves as tangible evidence that we are now a stronger exploration and production company positioned to further increase inventory to drive significant growth. The following are some of our major achievements in 2010:

 
·
Rosetta established a major new base of production and reserves in the Eagle Ford shale in South Texas. During 2010, we successfully delineated a 26,500 acre position within Gates Ranch, successfully drilling 25 wells and completing 16 wells.  We believe that we have identified a significant inventory of investment opportunities. This portfolio should lower our overall cost structure and deliver positive returns.  During 2010, we overcame numerous operating obstacles resulting from increasing demands for service equipment and infrastructure and entered into firm long-term natural gas agreements for transportation and processing capacity that will meet our current and projected production from the area for up to ten years.  In the third quarter of 2010, we announced the Light Ranch field discovery in another section of our Eagle Ford shale holdings, which further expands our drilling inventory.

 
 
·
We shifted our production portfolio to a more balanced mix of natural gas liquids, crude oil and natural gas.  This reduces our exposure to current low natural gas prices and allows us to take advantage of cyclical swings in energy commodity pricing.  For the month ended December 31, 2010, more than 30% of our production was from oil and NGLs and that amount will increase as Rosetta brings on-line more production from the Eagle Ford shale.  Approximately 56% of reserves that we have discovered in the Gates Ranch are liquids.

 
·
Our annual production rate averaged 138 MMcfe/d and we exited the year with a production rate of 157 MMcfe/d.  Of this exit rate, 54% was from the Eagle Ford shale and exemplifies the shift in our production base to unconventional resources during the year.  In addition, we drilled 100% successful exploratory wells in the Eagle Ford shale in 2010 that contributed to reserve growth of  36%.
 
 
·
We continue to divest our legacy assets that we believe do not offer the same investment opportunities or rate of returns as our unconventional resources.  During 2010, we sold assets located in Arkansas, Oklahoma, Mississippi, Texas, Louisiana, New Mexico and Wyoming for approximately $90.0 million with the monies redeployed into developing our positions. We believe the divestiture of these assets will decrease our cost structure through lower general and administrative expenses and lower operating costs. In 2011, we expect to complete the sales of our properties in the DJ Basin in Colorado and our holdings in the Sacramento Basin in California.
 
 
·
We retained our focus on financial flexibility as we continuously monitored our capital program results and diverted spending away from legacy natural gas producing areas to more promising opportunities offered by our high-return, high-value resource assets.  We refinanced our existing portfolio of debt through our Senior Notes offering and repayments under our revolving credit facility and term loan. We hedged selectively during the year to ensure stable future cash flows and balanced our capital spending program with asset sales and cash on hand.

 
·
We continued our exploratory evaluations of our large acreage position in the Southern Alberta Basin in Northwest Montana.  In 2010, we drilled four delineation wells in the area. Our assessment to date confirms oil hydrocarbons in place.  We are encouraged by what we are learning and intend to fully test our position.

Our business goals for 2011 are based on an announced capital program of $360.0 million, subject to program results and timing.  We enter 2011 with a project inventory base that is more than double the size of the previous year with a lower overall total cost structure than our previous holdings.  As we move forward with the development of our inventory, we expect to deliver long-term positive returns.  More than 90% of our planned spending will be allocated to the development of our Eagle Ford shale assets, primarily in the Gates Ranch area. Approximately 40 completions are planned with a fracture stimulation agreement in place to handle the increased activity. We have contracts in place for firm transportation and processing up to 205 MMcf/d of gross wellhead production with 115 MMcf/d of capacity available no later than the fourth quarter of 2011 and total contractual capacity reached by 2013. Our capital program reflects the impact of planned asset sales in the DJ Basin in Colorado and the Sacramento Basin in California.  It also includes funds for the continued exploration of the Southern Alberta Basin where we plan to drill another five vertical wells by early 2011.  We remain encouraged by the results of our drilling program and expect to add horizontal wells during 2011.  At this time, we believe that we have sufficient internal investment opportunities to grow the Company without acquiring additional properties.  However, we continue to evaluate opportunities that fit our business model and our strategic and economic objectives.

While 2010 was a successful year for Rosetta, we recognize that there are risks inherent to our industry and operating environment that could impact our ability to meet future goals.  Our business model takes into account these threats and we continually work to overcome potential risks to our ability to achieve our stated growth objectives and build our asset base.  We have reduced our exposure to weak natural gas commodity prices by diversifying our production base to a higher percentage of natural gas liquids and crude oil, which continue to trade at more profitable levels.  Heightened industry activity from other participants in the Eagle Ford shale, our largest producing area, led to some curtailments of production in 2010.  We have taken aggressive steps to ensure access to transportation and processing facilities and oil field services in the area.  However, we cannot completely control all external factors that could impact our operating environment.   Given the early stage of the Southern Alberta Basin play, there are still significant risks associated with an exploration program of this magnitude.  Identifying and responding effectively to potential threats in the marketplace is an important part of managing our business.
 
As part of our strategy to streamline our business, we announced the closing of our Denver office and the reorganization of Houston personnel.  As of December 31, 2010, we had incurred approximately $3.5 million of costs related to this reorganization and expect the reorganization to be completed by December 31, 2011.  While all future costs associated with the reorganization cannot be fully anticipated, we estimate that we will incur total costs of approximately $5.0 million. We believe the consolidation of our technical resources to Houston will enable us to capitalize on the dynamics and efficiencies of operating in a central location.
 
Our 2011 capital budget of $360.0 million takes into account the number of high-return opportunities afforded by our position in the Eagle Ford shale.  It is our intention to maintain our current debt levels and to continue to redeploy proceeds from planned asset sales to the development of our Eagle Ford shale properties.  We are confident that we can execute our capital program based on asset sale proceeds and internally generated cash flows plus cash on hand.  We monitor our liquidity situation continuously and respond prudently to changing market conditions, commodity prices or service costs.  In the event we encounter a situation in which there is not sufficient internal funds to meet projected funding of our organic opportunities or pursue attractive acquisitions, we would consider curtailing our capital spending, drawing on the unused capacity under our existing revolving credit facility or accessing capital markets.

 
Our borrowing base under our revolving credit facility was confirmed by our lenders in October 2010 at $365.0 million.  According to our agreement, the borrowing base was adjusted in December 2010 to $325.0 million after the successful divestitures of our Pinedale and San Juan assets.  As of December 31, 2010, we had $195.0 million of available borrowing capacity under our revolving credit facility.  There has not been any indication that draws under our credit facility will be restricted below current availability. The next redetermination is scheduled to begin in April 2011. Our ability to raise additional capital depends on the state of the financial markets that are subject to change depending upon economic and industry conditions.  Therefore, the availability and price of capital in the financial markets could negatively affect our liquidity position and cost of borrowed money.  We work closely with our lenders to stay abreast of market and creditor conditions. Our capital expenditures are primarily in areas where we act as operator and have 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 monitor partner situations routinely.

Financial Highlights

Our consolidated financial statements reflect total revenue of $308.4 million on total volumes of 50.2 Bcfe for the year ended December 31, 2010.  Operating income for the year ended December 31, 2010 was $71.5 million and included depreciation, depletion and amortization (“DD&A”) expense of $116.6 million, lease operating expense of $51.1 million and $14.1 million of compensation expense for stock-based compensation granted to employees included in General and administrative costs. Total net other income for the year ended December 31, 2010 was comprised of interest expense (net of capitalized interest) on our long-term debt offset by interest income on short-term cash investments.

Results of Operations

The following table summarizes the components of our revenues for the periods indicated, as well as each period’s production volumes and average prices:

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(In thousands, except per unit amounts)
 
Revenues:
                 
Natural gas sales
  $ 208,688     $ 250,684     $ 398,268  
Oil sales
    54,542       21,763       55,736  
NGL sales
    45,200       21,504       45,343  
Total revenues
  $ 308,430     $ 293,951     $ 499,347  
                         
Production:
                       
Gas (Bcf)
    39.2       44.5       47.7  
Oil (MBbls)
    738.0       393.9       546.4  
NGLs (MBbls)
    1,096.0       620.1       440.8  
Total equivalents (Bcfe)
    50.2       50.6       53.6  
                         
$ per unit:
                       
Avg. gas price per Mcf, excluding hedging
  4.50     $ 3.91     8.74  
Avg. gas price per Mcf
    5.32       5.63       8.35  
Avg. oil price per Bbl
    73.91       55.25       102.00  
Avg. NGL price per Bbl
    41.24       34.68       102.87  
Avg. revenue per Mcfe
    6.14       5.81       9.32  

Revenues
 
Our revenues are derived from the sale of our natural gas, oil and NGL 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, 2010 Compared to the Year Ended December 31, 2009

Total revenue for the year ended December 31, 2010 was $308.4 million, which was an increase of $14.4 million, or 5%, from the year ended December 31, 2009. Excluding the effects of hedging, approximately 64%, 20% and 16% of revenue for the year ended December 31, 2010 was attributable to natural gas sales, oil and NGL sales respectively, as compared to 80%, 10%, and 10%, respectively, for 2009.
 
 
Natural Gas.  Including the realized impact of derivative instruments for  the year ended December 31, 2010, natural gas revenue decreased by 17%, or $42.0 million, from the comparable period in 2009. Of this decrease, $44.1 million was attributable to the effect of gas hedging activities and $20.6 million was attributable to decreased volumes.  This decrease was offset by an increase of $22.7 million attributable to higher average realized prices in 2010.  The average realized natural gas price, including the effects of hedging, decreased 6%, or $0.31, to $5.32 per Mcf for the year ended December 31, 2010 as compared to $5.63 per Mcf for the same period in 2009.  Natural gas production volumes decreased overall by 12%, or 5.3 Bcf, for the year ended December 31, 2010, primarily due to asset divestitures of non-core properties, the suspension of drilling programs in areas that produce primarily from dry gas reservoirs and the natural decline in our non-core Gulf Coast properties.
 
Crude Oil.  For the year ended December 31, 2010, oil revenue increased by 150%, or $32.7 million, primarily due to the increase of $18.66 per Bbl in the average realized oil price from $55.25 per Bbl for the year ended December 31, 2009 to $73.91 per Bbl for the year ended December 31, 2010.   Oil volumes also increased by 87%, or 344.1 MBbls, to 738.0 MBbls for the year ended December 31, 2010 from 393.9 MBbls for the year ended December 31, 2009.  The increase in oil production volumes was due to our success in the Eagle Ford shale.

NGLs.  For the year ended December 31, 2010, NGL revenue increased by 110%, or $23.7 million, primarily due to the increase of $6.56 per Bbl in the average realized NGL price from $34.68 per Bbl for the year ended December 31, 2009 to $41.24 per Bbl for the year ended December 31, 2010.  NGL volumes increased by 77%, or 475.9 MBbls, to 1,096.0 MBbls for the year ended December 31, 2010 from 620.1 MBbls for the year ended December 31, 2009.  The increase in NGL production volumes was due to our success in the Eagle Ford shale, reflecting our shift in strategy to a more liquids-based production mix.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

Total revenue for the year ended December 31, 2009 was $294.0 million, which was a decrease of $205.4 million, or 41%, from the year ended December 31, 2008. Excluding the effects of hedging, approximately 80%, 10% and 10% of revenue for the year ended December 31, 2010 was attributable to natural gas sales, oil and NGL sales respectively, as compared to 80%, 11%, and 9%, respectively, for 2009.
 
 Natural Gas.  Including the realized impact of derivative instruments for  the year ended December 31, 2009, natural gas revenue decreased by 37%, or $147.6 million, from the comparable period in 2008.  Of this decrease, $27.1 million was attributable to decreased volumes and $120.5 million was attributable to lower average realized prices in 2009.  The average realized natural gas price including the effects of hedging decreased 33%, or $2.72, to $5.63 per Mcf for the year ended December 31, 2009 as compared to $8.35 per Mcf for the same period in 2008.  The effect of gas hedging activities on natural gas revenue for the year ended December 31, 2009 was an increase of $76.6 million, or an increase of $1.72 per Mcf, as compared to a decrease of $18.7 million, or a decrease of $0.39 per Mcf, for the year ended December 31, 2008.  Production volumes decreased overall by 7%, or 3.2 Bcf for the year ended December 31, 2009, primarily due to a natural decline in our non-core Gulf of Mexico properties, the suspension of drilling programs during 2009 in areas where we were active during 2008 and the suspension of non-essential workover and recompletion activity in all areas for a portion of 2009 for the purpose of cash management during the economic downturn.
 
Crude Oil.  For the year ended December 31, 2009, oil revenue decreased by 61%, or $34.0 million, primarily due to the decrease of $46.75 per Bbl in the average realized oil price from $102.00 per Bbl for the year ended December 31, 2008 as compared to $55.25 per Bbl for the year ended December 31, 2009.   Oil volumes also decreased by 28%, or 152.5 MBbls, to 393.9 MBbls for the year ended December 31, 2009 from 546.4 MBbls for the year ended December 31, 2008.  The decrease in oil production volumes was due to a natural decline in our non-core Gulf of Mexico and Texas State Waters properties.

NGLs.  For the year ended December 31, 2009, NGL revenue decreased by 53%, or $23.8 million, primarily due to the decrease of $68.19 per Bbl in the average realized NGL price from $102.87 per Bbl for the year ended December 31, 2008 as compared to $34.68 per Bbl for the year ended December 31, 2009.  NGL volumes increased by 41%, or 179.3 MBbls, to 620.1 MBbls for the year ended December 31, 2009 from 440.8 MBbls for the year ended December 31, 2008.  The increase in NGL production volumes was due to the recognition in 2009 of processed liquid volumes for the first time from our Lobo trend properties.

Operating Expenses
 
The following table summarizes our production costs and operating expenses for the periods indicated:

 
   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(In thousands, except per unit amounts)
 
Lease operating expense
  $ 51,085     $ 60,773     $ 55,694  
Production taxes
    5,953       6,131       13,528  
Depreciation, depletion and amortization
    116,558       121,042       198,862  
Impairment of oil and gas properties
    -       379,462       444,369  
General and administrative costs
    56,332       46,993       52,846  
                         
$ per unit:
                       
Avg. lease operating expense per Mcfe
  $ 1.02     $ 1.20     $ 1.04  
Avg. production taxes per Mcfe
    0.12       0.12       0.25  
Avg. DD&A per Mcfe
    2.32       2.39       3.71  
Avg. production costs per Mcfe (1)
    3.34       3.59       4.75  
Avg. production costs per Mcfe (2)     3.15       3.31       4.53  
Avg. General and administrative costs per Mcfe
    1.12       0.93       0.99  
Avg. General and administrative costs per Mcfe, excluding stock-based compensation      0.84       0.78       0.85  
 
 
(1)
Production costs per Mcfe include lease operating expense and DD&A.
 
(2)
Production costs per Mcfe includes lease operating expense and DD&A and excludes production and ad valorem taxes.
 
The ultimate outcome of each of these matters cannot be absolutely determined, and 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 for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the consolidated financial statements.

Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009

Lease Operating Expense.  Lease operating expense decreased $9.7 million for the year ended December 31, 2010 as compared to the same period for 2009. This overall decrease was primarily due to cost control measures and asset divestitures.  Lease operating expense included workover costs of $0.04 per Mcfe, ad valorem taxes of $0.19 per Mcfe and insurance of $0.03 per Mcfe for the year ended December 31, 2010 as compared to workover costs of $0.08 per Mcfe, ad valorem taxes of $0.29 per Mcfe and insurance of $0.03 per Mcfe for the same period in 2009.

Production Taxes.  Production taxes as a percentage of unhedged natural gas, oil and NGL sales were 2.2% for the year ended December 31, 2010 as compared to 2.8% for the year ended December 31, 2009.  This decrease was primarily due to certain production tax credits in the State of Texas.

Depreciation, Depletion, and Amortization.  DD&A expense decreased $4.4 million for the year ended December 31, 2010 as compared to the same period for 2009.  The decrease was due to a 1% decrease in total production and a lower DD&A rate for 2010 compared to 2009 due to the full cost ceiling test impairment charges recognized in the first quarter of 2009, which decreased the full cost pool.  The DD&A rate for the year ended December 31, 2010 was $2.32 per Mcfe while the rate for the year ended December 31, 2009 was $2.39 per Mcfe.

Impairment of Oil and Gas Properties.  Based on quarterly ceiling test computations using a twelve-month average price computed as an average of first day of the month prices, adjusted for hedges of oil and gas, we were not required to record a write-down at December 31, 2010 and no write-down occurred during the twelve months ended December 31, 2010.  However, based on the quarterly ceiling test computations using hedge adjusted market prices during the year ended December 31, 2009, at March 31, 2009, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling and we recorded a pre-tax, non-cash impairment expense of $379.5 million.
 
General and Administrative Costs.  General and administrative costs, net of capitalized exploration and development overhead costs of $7.8 million, increased by $9.3 million for the year ended December 31, 2010 as compared to the same period for 2009.  The increase in general and administrative costs was primarily related to a $6.7 million increase in stock-based compensation due to the increased stock price, a $4.5 million increase in salaries, wages and bonuses, a $2.5 million increase in benefit costs offset by an increase of $1.5 million in billable field personnel, a $2.6 million increase in capitalizable geological and geophysical expenses and $0.3 million of other administrative costs.

Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008

Lease Operating Expense.  Lease operating expense increased $5.1 million for the year ended December 31, 2009 as compared to the same period for 2008. This overall increase was primarily due to the 2008 South Texas Constellation, Pinedale and Petroflow acquisitions as 2009 was the first full year of recording expenses.   Lease operating expense included workover costs of $0.08 per Mcfe, ad valorem taxes of $0.29 per Mcfe and insurance of $0.03 per Mcfe for the year ended December 31, 2009 as compared to workover costs of $0.14 per Mcfe, ad valorem taxes of $0.21 per Mcfe and insurance of $0.03 per Mcfe for the same period in 2008.

Production Taxes.   Production taxes as a percentage of unhedged natural gas, oil and NGL sales were 2.8% for the year ended December 31, 2009 as compared to 2.6% for the year ended December 31, 2008.  This increase was the result of production tax credits for the year ended December 31, 2008 as compared to the same period for 2009.

 
Depreciation, Depletion, and Amortization.  DD&A expense decreased $77.8 million for the year ended December 31, 2009 as compared to the same period for 2008.  The decrease was due to a 6% decrease in total production and a lower DD&A rate for 2009 compared to 2008 due to the full cost ceiling test impairment charges recognized during the second half of 2008 and during the first quarter of 2009, which decreased the full cost pool.  The DD&A rate for the year ended December 31, 2009 was $2.39 per Mcfe while the rate for the year ended December 31, 2008 was $3.71 per Mcfe.

Impairment of Oil and Gas Properties.  Based on the quarterly ceiling test computations using hedge adjusted market prices during the year ended December 31, 2009, at March 31, 2009, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling and we recorded a pre-tax, non-cash impairment expense of $379.5 million.  The application of the new SEC guidance did not impact the ceiling test for the year ended 2009.  Based on the quarterly ceiling test computations using hedge adjusted market prices during the year ended December 31, 2008 and in conjunction with the downward revisions of a portion of our reserves in the third and fourth quarters of 2008, the net capitalized costs of oil and natural gas properties exceeded the cost center ceiling and we recorded a pre-tax, non-cash impairment expense of $444.4 million.
 
General and Administrative Costs.  General and administrative costs, net of capitalized exploration and development overhead costs of $4.8 million, decreased by $5.9 million for the year ended December 31, 2009 as compared to the same period for 2008.  The decrease in general and administrative costs incurred in 2009 was primarily related to decreases of $12.1 million in legal fees related to the Calpine litigation, which settled during 2008, and an increase of $1.4 million in billable field personnel offset by a $3.1 million decrease in capitalizable geological and geophysical expenses, a $2.2 million increase in salaries and wages resulting from the additional technical personnel hired during 2009 and a $2.7 million increase in bonus expense.

Total Other Expense
 
Total other expense includes Interest expense, net of interest capitalized, Interest income and Other income/expense, net which increased $7.6 million for the year ended December 31, 2010 as compared to the same period in 2009.  The increase in Total other expense was primarily due to an increase in interest expense associated with higher amounts of outstanding debt.  Long-term debt outstanding as of December 31, 2010 was $61.3 million higher as compared to December 31, 2009.  The weighted average interest rate for the twelve months ended December 31, 2010 was 7.06% compared to 5.18% for the same period in 2009.  This increase in the weighted average interest rate was primarily due to the higher interest rate associated with the Senior Notes.

Other expense decreased $7.3 million for the year ended December 31, 2009 as compared to the same period in 2008.  The decrease in other expense was primarily the result of a $12.4 million charge related to the settlement of litigation with Calpine in 2008 for which there were no related expenses during 2009 offset by a $4.6 million increase in interest expense due to higher interest rates on our credit facilities and increased amortization of deferred loan fees and original issue discount related to our credit facilities during the first quarter of 2009.

Provision for Income Taxes
 
Our 2010 income tax expense was $26.5 million. For the year ended December 31, 2010, the effective tax rate was 58.2% compared to the effective tax rate of 36.5% for the year ended December 31, 2009 and 37.5% for the year ended December 31, 2008.  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, the non-deductibility of certain incentive compensation and a valuation allowance against certain state deferred tax assets.

The Company provides for deferred income taxes on the difference between the tax basis of an asset or liability and its carrying amount in the financial statements in accordance with authoritative guidance for 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. As of December 31, 2010, the Company had a deferred tax asset of $142.7 million, compared to a deferred tax asset of approximately $169.7 million at December 31, 2009, resulting primarily from the difference between the book basis and tax basis of our oil and natural gas properties and net operating loss carryforwards. Realization of the deferred tax asset is dependent, in part, on generating sufficient taxable income from the production of oil and natural gas properties prior to the expiration of loss carryforwards.

In connection with the planned asset divestitures in the DJ Basin in Colorado and in the Sacramento Basin in California, the Company concluded that it is more likely than not that the deferred tax assets for these states including NOLs will not be realized. Therefore, valuation allowances have been established for these items as well as state NOLs in other jurisdictions in which the Company previously operated but has since divested of operating assets.  The Company will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.
 
 
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 may also limit our earnings potential in periods of rising commodity prices. The effects of these derivative transactions on our natural gas sales are discussed above under “Results of Operations – Revenues – Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 - Natural Gas” and “Results of Operations – Revenues – Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008 - Natural Gas.” The majority of our capital expenditures are discretionary and could be curtailed if our cash flows decline from expected levels.  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 Credit Facility. Our amended and restated revolving credit agreement (the “Restated Revolver”) provides for a senior secured revolving line of credit of up to $600.0 million and matures on July 1, 2012. Availability under the Restated Revolver is restricted to the borrowing base, which is subject to review and adjustment on a semi-annual basis and other interim adjustments, including adjustments based on our hedging arrangements as well as asset divestitures. Our borrowing base is dependent on a number of factors, including our level of reserves as well as the pricing outlook at the time of the redetermination. A reduction in capital spending could result in a reduced level of reserves thus causing a reduction in the borrowing base.

Our borrowing base was confirmed by our lenders in October 2010 at $365.0 million.  In accordance with our agreement, the borrowing base was adjusted in December 2010 to $325.0 million after the successful divestitures of our Pinedale and San Juan assets. As of December 31, 2010, we had $195.0 million of available borrowing capacity under our Restated Revolver.  Amounts outstanding under the Restated Revolver bear interest at specified margins over the London Interbank Offered Rate (LIBOR) of 2.25% to 3.00%. Borrowings under the Restated Revolver are collateralized by perfected first priority liens and security interests on substantially all of our assets, including a mortgage lien on oil and natural gas properties having at least 80% of the pre-tax SEC PV-10 reserve value, a guaranty by all of our domestic subsidiaries, and a pledge of 100% of the membership interests of our domestic subsidiaries. Collateralized amounts under the mortgages are subject to semi-annual reviews based on updated reserve information. We are subject to the financial covenants as defined in our credit agreement.  The terms of the credit agreement require us to maintain a minimum current ratio of consolidated current assets, including the unused amount of available borrowing capacity, to consolidated current liabilities, excluding certain non-cash obligations, of not less than 1.0 to 1.0 as of the end of each fiscal quarter.  The terms of the credit agreement also require us to maintain a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, 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 after giving pro forma effect to acquisitions and divestitures.  At December 31, 2010, our current ratio was 3.5 and the leverage ratio was 1.7.  In addition, we are subject to covenants limiting dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at December 31, 2010.   As of February 18, 2011, we had $130.0 million outstanding, with $195.0 million available for borrowing under the Restated Revolver. The borrowing base will be subject to further adjustment pending the potential DJ Basin and Sacramento Basin divestitures.

Second Lien Term Loan.   Our amended and restated term loan (the “Restated Term Loan”) matures on October 2, 2012. On April 15, 2010, we repaid $80.0 million of variable rate borrowings outstanding under the Restated Term Loan, which bore interest at LIBOR plus 8.5% with a LIBOR floor of 3.5%.  In connection with the repayment, we paid an early termination premium of $1.3 million. In accordance with authoritative guidance for derivative instruments and hedging activities, we evaluated the LIBOR floor as an embedded derivative and concluded that because the terms were clearly and closely related to the debt instrument, it did not represent an embedded derivative to be accounted for separately. As of December 31, 2010, we had $20.0 million of fixed rate borrowings outstanding bearing interest at 13.75% under the Restated Term Loan. The loan is collateralized by second priority liens on substantially all of the Company’s assets. We are subject to the financial covenants as defined in our term loan agreement. We are required under the term loan agreement to maintain a minimum reserve ratio of our total reserve value to total debt of not less than 1.5 to 1.0 as of the end of each fiscal quarter.  The terms of the agreement also require us to maintain a maximum leverage ratio of total debt to earnings before interest expense, income taxes and noncash items, such as depreciation, depletion, amortization and impairment, of not greater than 4.0 to 1.0, calculated at the end of each fiscal quarter for the four fiscal quarters then ended.  At December 31, 2010, our reserve coverage ratio was 2.2 and the leverage ratio was 1.7.  In addition, the Company is subject to covenants, including limitations on dividends and other restricted payments, transactions with affiliates, incurrence of debt, changes of control, asset sales, and liens on properties. We were in compliance with all covenants at December 31, 2010.   We also have the right to prepay the fixed rate borrowings outstanding under the Restated Term Loan with a make-whole amount at a discount factor equal to 1% plus the U.S. Treasury yield security having a maturity closest to the remaining life of the loan.

Senior Notes.  On April 15, 2010, we issued and sold $200.0 million in aggregate principal amount of 9.500% Senior Notes due 2018 in a private offering.  The Senior Notes were issued under an indenture (the “Indenture”) with Wells Fargo Bank, National Association, as trustee. Provisions of the Indenture limit our ability to, among other things, incur additional indebtedness; pay dividends on our capital stock or purchase, repurchase, redeem, defease or retire capital stock or subordinated indebtedness; make investments; incur liens; create any consensual restriction on the ability of our restricted subsidiaries to pay dividends, make loans or transfer property to us; engage in transactions with affiliates; sell assets; and consolidate, merge or transfer assets. The Indenture also contains customary events of default. Proceeds from the Senior Notes offering were used to repay $114.0 million outstanding under our Restated Revolver and $80.0 million of variable rate borrowings outstanding under our Restated Term Loan, and to pay for fees and expenses associated with the offering. Interest is payable on the Senior Notes semi-annually on April 15 and October 15. On September 21, 2010, we exchanged all of the privately placed Senior Notes for registered Senior Notes which contain terms substantially identical to the terms of the privately placed notes.

 
As of December 31, 2010, we had total outstanding borrowings of $350.0 million and for the year ended December 31, 2010, our weighted average borrowing rate was 7.06%.

Working Capital
 
At December 31, 2010, we had a working capital surplus of $22.8 million as compared to a working capital surplus of $45.7 million at December 31, 2009.  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.  The surplus for 2010 was largely caused by the increases in our receivables and derivative instruments.  As of December 31, 2010, the working capital asset balances of our cash and cash equivalents and derivative instruments were approximately $41.6 million and $19.1 million, respectively.  In addition, the Accrued liability balance included in the working capital liability was approximately $57.0 million as of December 31, 2010.
 
Cash Flows

   
Year Ended December 31,
 
   
2010
   
2009
   
2008
 
   
(In thousands)
Cash flows provided by operating activities
  $ 176,861     $ 160,501     $ 374,719  
Cash flows used in investing activities
    (251,621 )     (123,865 )     (393,070 )
Cash flows (used in) provided by financing activities
    55,138       (18,235 )     57,990  
Net (decrease) increase in cash and cash equivalents
  $ (19,622 )   $ 18,401     $ 39,639  

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 continued to be a primary source of liquidity and capital used to finance our capital expenditures for the year ended December 31, 2010.

Cash flows provided by operating activities increased by $16.4 million for the year ended December 31, 2010 as compared to the same period for 2009. This increase was largely due to higher oil, NGL and natural gas prices and increased oil and NGL production during 2010 compared to 2009. 
 
Cash flows provided by operating activities decreased by $214.2 million for the year ended December 31, 2009 as compared to the same period for 2008. This decrease was largely due to lower oil and natural gas prices and production during 2009 compared to 2008.   For the year ended December 31, 2009, we had net losses of $219.2 million with a decrease in production of 6% as compared to the year ended December 31, 2008 with net losses of $188.1 million.

Investing Activities.  The primary driver of cash used in investing activities is capital spending.
 
Cash flows used in investing activities increased by $127.8 million for the year ended December 31, 2010 as compared to the same period for 2009.  The increase was primarily attributable to increased expenditures of $187.9 million for purchases to develop oil and gas properties offset with a decrease in investing activities of $63.6 million due to asset sales.  For the year ended December 31, 2010, we incurred approximately $339.4 million in capital expenditures as compared to approximately $135.4 million for the year ended December 31, 2009.  During the year ended December 31, 2010, we participated in the drilling of 127 gross wells as compared to the drilling of 43 gross wells for the year ended December 31, 2009.

Cash flows used in investing activities decreased by $269.2 million for the year ended December 31, 2009 as compared to the same period for 2008, which primarily reflected reduced expenditures for the acquisition and development of oil and gas properties and drilling.  Acquisitions of oil and gas properties decreased $159.3 million and purchases of oil and gas assets decreased $87.4 million from 2008 to 2009 as a result of our decision to exercise prudence and caution with our capital spending in order to preserve our liquidity and maximize our financial position during a period of low commodity prices and reduced demand for natural gas.  For the year ended December 31, 2009, we incurred approximately $135.4 million in capital expenditures as compared to $334.5 million for the year ended December 31, 2008.  During the year ended December 31, 2009, we participated in the drilling of 43 gross wells as compared to the drilling of 184 gross wells for the year ended December 31, 2008.

 
Financing Activities.  The primary drivers of cash provided by (used in) financing activities are borrowings and repayments under the Restated Revolver and equity transactions associated with the exercise of stock options, and the acquisition of treasury shares from employees and directors to pay tax withholding upon the vesting of restricted stock.
 
Cash flows provided by financing activities increased by $73.4 million for the year ended December 31, 2010 as compared to the same period for 2009.  The net increase was primarily related to the borrowings under the Restated Revolver of $64.0 million during the year ended December 31, 2010, the net impact of the $200.0 million issuance of our Senior Notes and repayment of $80.0 million under the Restated Term Loan and $124.0 million under the Restated Revolver.

Cash flows provided by financing activities decreased by $76.2 million for the year ended December 31, 2009 as compared to the same period for 2008.  The net decrease was primarily related to payments of $40.0 million made in 2009 under the Restated Revolver and $5.9 million of deferred loan fees related to the restated credit facilities netted with $28.4 million of borrowings in 2009 compared to $55.0 million of borrowings in 2008.  In addition, there was a decrease of approximately $3.6 million in the stock options exercised for the year ended December 31, 2009 compared to 2008.
 
Commodity Price Risk, Interest Rate Risk and Related Hedging Activities

The energy markets have historically been very volatile and oil, NGL and natural gas prices will be subject to wide fluctuations in the future. To mitigate our exposure to changes in commodity prices, management hedges oil, NGL 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 enable us to achieve a more predictable cash flow. Consistent with this policy, we have entered into a series of natural gas, oil and NGL fixed price swaps and costless collars for each year through 2012. Our fixed price swap and costless collar agreements require payments to (or receipts from) counterparties based on the differential between a fixed price and a variable price for a notional quantity of oil, NGLs, and natural gas without the exchange of underlying volumes. The notional amounts of these financial instruments were based on expected production from existing wells at inception of the hedge instruments.

Borrowings under our Restated Revolver mature on July 1, 2012 and bear interest at a LIBOR-based rate. To mitigate our exposure to rising interest rates, we entered into a series of interest rate swap agreements that expired in December 2010.  We may enter into additional interest rate swap agreements in the future to mitigate interest rate risk if the costs are not prohibitive.
 
The following table sets forth the results of commodity fixed price and costless collars and interest rate swap derivative settlements:

   
For the Year Ended December 31,
 
   
2010
   
2009
   
2008
 
Natural Gas
                 
Quantity settled (MMBtu)
    14,645,000       20,856,465       26,684,616  
Increase (decrease) in natural gas sales revenue (In thousands)
  $ 30,740     $ 76,567     $ (18,669 )
Interest Rate Swaps
                       
Increase in interest expense (In thousands)
  $ (978 )   $ (1,289 )   $ (1,158 )

In accordance with the authoritative guidance for derivatives, 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).
 
As of December 31, 2010, our commodity hedge positions were with counterparties that were also 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, 2010, we had no deposits for collateral.

Capital Requirements

Our capital expenditures for the year ended December 31, 2010 were $339.4 million, including capitalized internal costs directly identified with acquisition, exploration and development activities of $7.8 million, capitalized interest of $4.0 million and corporate and other capital costs of $2.0 million.  We have plans to execute an organic capital program in 2011 of $360.0 million that can be funded from internally generated cash flows, divestiture proceeds and available cash.  We also have the discretion to use our available borrowing base to fund capital expenditures, including acquisitions.

 
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, 2010, the aggregate amounts of our contractually obligated payment commitments for the next five years were as follows:

   
Payments Due By Period
 
   
Total
   
2011
   
2012 to 2013
   
2014 to 2015
   
2016 & Beyond
 
   
(In thousands)
 
Senior secured revolving line of credit
  $ 130,000     $ -     $ 130,000     $ -     $ -  
Second lien term loan
    20,000       -       20,000       -       -  
Senior notes
    200,000       -       -       -       200,000  
Operating leases
    10,784       3,400       6,716       668       -  
Interest payments on long-term debt (1)
    130,600       23,197       38,528       38,528       30,347  
Field service agreements
    23,437       23,437       -       -       -  
Rig commitments
    4,758       4,758       -       -       -  
Total contractual obligations
  $ 519,579     $ 54,792     $ 195,244     $ 39,196     $ 230,347  
 
(1) Future interest payments were calculated based on interest rates and amounts outstanding at December 31, 2010.

Asset Retirement Obligations. We also had total liabilities of $27.9 million at December 31, 2010 related to asset retirement obligations that are excluded from the table above.  Of the total ARO, the current portion was approximately $9.3 million at December 31, 2010 and was included in Accrued liabilities on the Consolidated Balance Sheet.  The long-term portion of ARO was approximately $18.6 million at December 31, 2010 and was included in Other long-term liabilities on the Consolidated Balance Sheet. 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 legal proceedings arising in the normal course of business. The ultimate outcome of each of these matters cannot be absolutely determined, and the liability the Company may ultimately incur with respect to any one of these matters in the event of a negative outcome may be in excess of amounts currently accrued for with respect to such matters. Net of available insurance and performance of contractual defense and indemnity obligations, where applicable, management does not believe any such matters will have a material adverse effect on the Company’s financial position, results of operations or cash flows.

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.
 
 
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 and 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 a twelve-month average price computed as an average of first day of the month prices, period-end costs and a 10% discount rate.  Prior to December 31, 2009, the assessment for impairment under the full cost method required the use of period-end pricing when evaluating the carrying value of oil and gas properties against the net present value of future cash flows from the related proved reserves.
 
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.  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 DD&A 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 DD&A 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 NSAI who then performs an annual year-end reserve report audit. 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 impacts property, plant and equipment amounts in the consolidated balance sheet and the DD&A amounts in the consolidated statement of operations.  Current guidance dictates the use of a twelve-month first day of the month historical average price adjusted for basis and quality differentials for oil and natural gas and holds costs in effect as of the last day of the quarter or annual period constant in calculating reserves.  Prior to December 31, 2009, the guidance dictated that year-end prices adjusted for basis and quality differentials and costs be used in calculating reserves.  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 authoritative guidance, 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 current ceiling calculation utilizes a twelve-month first day of the month historical average price.  The costs in effect as of the last day of the quarter or annual period are held constant.  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.  For more information regarding the full cost ceiling limitation, refer to Item 8. “Financial Statements and Supplementary Data, Note 2 – Summary of Significant Accounting Policies.”

 
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 would decrease or increase the DD&A rate by approximately $0.11 to $0.13 per Mcfe.  This estimated impact is based on current data at December 31, 2010 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.  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, 2010, our full cost pool had approximately $91.1 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 authoritative guidance for accounting for asset retirement obligations. This guidance 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, natural gas and NGL prices 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 oil, natural gas and NGL production through 2012.
 
 
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 December 2010.  These transactions were recorded in our financial statements in accordance with authoritative guidance for accounting for derivative instruments and hedging activities.  Although not risk free, we believed these agreements reduced our exposure to commodity price fluctuations and changes in interest rates and thereby enabled us to achieve a more predictable cash flow. We did not enter into derivative agreements for trading or other speculative purposes.
 
In accordance with amended guidance, 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 flows 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 on the Consolidated Statement of Operations.
 
Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued authoritative guidance regarding fair value measurements.  This guidance defined fair value, established a framework for measuring fair value, expanded the related disclosure requirements and was effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those years.  This guidance did not require any new fair value measurements; however, it did require some entities to change their measurement practices.  In February 2008, the FASB issued additional guidance which delayed the effective date of fair value accounting 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, we implemented the guidance for measuring the fair value of financial assets and liabilities.  Beginning January 1, 2009, we implemented the guidance for nonfinancial assets and liabilities.  The adoption of this guidance did not have an impact on our consolidated financial position, results of operations or cash flows.  In October 2008, the FASB issued guidance on determining the fair value of a financial asset when the market for that asset is not active.  This guidance clarifies the application of fair value accounting 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 guidance was effective upon issuance, including prior periods for which financial statements have not been issued.  We applied this guidance to financial assets measured at fair value on a recurring basis at September 30, 2009.  The adoption of this guidance did not have a significant impact on our consolidated financial position, results of operations or cash flows.  In April 2009, the FASB issued authoritative guidance to provide additional application guidance and enhance disclosures regarding fair value measurements and impairments of securities.  This guidance provides guidelines for making fair value measurements for assets and liabilities for which the volume and level of activity for the asset or liability have significantly decreased or for transactions that are not orderly more consistent with the principles presented in earlier guidance, enhances consistency in financial reporting by increasing the frequency of fair value disclosures, and provides additional guidance designed to create greater clarity and consistency in accounting for and presenting impairment losses on securities for other-than-temporary impairments.  This guidance is effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009.  We applied this guidance for the period ended June 30, 2009 and the Company’s financial assets and liabilities were measured at fair value on a recurring basis.  The Company discloses its recognized non-financial assets and liabilities, such as asset retirement obligations and other property and equipment, at fair value on a non-recurring basis.  For non-financial assets and liabilities, the Company is required to disclose information that enables users of its financial statements to assess the inputs used to develop these measurements. The adoption did not have a significant impact on the Company’s 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 authoritative guidance regarding the accounting for stock-based compensation. Under the provisions of this guidance, stock-based compensation cost for options 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 for future grants may differ materially from that recorded in the current period.  Stock-based compensation cost for restricted stock is estimated at the grant date based on the award’s fair value which is equal to the average high and low common stock price on the date of grant and is recognized as expense over the requisite service period.  Stock-based compensation for performance share units (“PSUs”) is measured at the end of each reporting period through the settlement date using the quarter-end closing common stock prices for awards that are solely based on performance conditions or a Monte Carlo model for awards that contain market conditions to reflect the current fair value.  Compensation expense is recognized ratably over the performance period based on our estimated achievement of the established metrics.  Compensation expense for awards with performance conditions will only be recognized for those awards for which it is probable that the performance conditions will be achieved and which are expected to vest.  The compensation expense will be estimated based upon an assessment of the probability that the performance metrics will be achieved, current and historical forfeitures, and the Board’s anticipated vesting percentage.  Compensation expense for awards with market conditions is measured at the end of each reporting period based on the fair value derived from the Monte Carlo model which incorporates a risk-neutral valuation approach to value these awards.  The Monte Carlo model requires various highly judgmental assumptions to determine the fair value of the awards.  This model samples paths of ours and the S&P 400 O&G E&P Industry Index’s (the “Index”) stock price and calculates the resulting change in cash flow multiple at the end of the forecasted performance period.   This model iterates these randomly forecasted results until the distribution of results converge on a mean or estimated fair value.  The five primary inputs for the Monte Carlo model are the risk-free rate, independent analyst cash flow per share estimates for the Index and us, volatility of the equities of the Index and us, expected dividends, where applicable, and various historical market data. The risk-free rate was generated from Bloomberg for United States Treasuries with a two-year tenor.  Volatility was set equal to the annualized daily volatility measured over a historic 400-day period ending on the reporting date for the Index and us.   No forfeiture rate is assumed for this type of award.  Expense related to these awards can be volatile based on the Company’s comparative performance at the end of each quarter.  If any of the assumptions used in the Monte Carlo model change significantly, stock-based compensation expense may differ materially in the future from that recorded in the current period.  See Item 8. “Financial Statements and Supplementary Data, Note 12 – Stock-Based Compensation”.

 
Revenue Recognition
 
We use the sales method of accounting for the sale of our 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, we record a liability.
 
Since there is a ready market for natural gas, crude oil and NGLs, we sell our 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 our net interest or nominated deliveries of production volumes. We record our share of revenues based on sales volumes and contracted sales prices. The sales price for natural gas, NGLs 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 us. Historically, these adjustments have been insignificant. In addition, natural gas and crude oil volumes sold are not significantly different from our share of production.
 
We 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 our 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 authoritative guidance for 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.  In connection with the planned asset divestitures in the DJ Basin in Colorado and in the Sacramento Basin in California, we concluded that it is more likely than not that the deferred tax assets for these states including NOLs will not be realized. Therefore, valuation allowances have been established for these items as well as state NOLs in other jurisdictions in which we previously operated but have since divested of operating assets.  We will continue to assess the need for a valuation allowance against deferred tax assets considering all available evidence obtained in future reporting periods.  See Item 8. “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 $0.5 million for the year ended December 31, 2010.
 
Authoritative guidance for accounting for uncertainty in income taxes 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 have been applied or may impact the Company in future periods.

Financing Receivables. In July 2010, the FASB issued authoritative guidance related to improving disclosures around the credit quality of financing receivables and associated allowances for credit losses. This guidance requires a reporting entity to provide additional disclosures about the nature of the credit risk inherent in the entity’s portfolio of financing receivables, how that risk is analyzed and the assessment in determining the allowance for credit losses, as well as discussion of the changes in the allowance for credit losses. The guidance will be required for interim and annual reporting periods effective January 1, 2011. As we have no financing receivables, this guidance will not impact our disclosures and will not impact our consolidated financial position, results of operations or cash flows.

 
Fair Value Measurements.   In January 2010, the FASB issued authoritative guidance related to improving disclosures about fair value measurements. This guidance requires separate disclosures of the amounts of transfers in and out of Level 1 and Level 2 fair value measurements and a description of the reason for such transfers. In the reconciliation for Level 3 fair value measurements using significant unobservable inputs, information about purchases, sales, issuances and settlements shall be presented separately. These disclosures will be required for interim and annual reporting periods effective January 1, 2010, except for the disclosures related to the purchases, sales, issuances and settlements in the roll forward activity of Level 3 fair value measurements, which are effective on January 1, 2011. This guidance will require additional disclosures but will not impact our consolidated financial position, results of operations or cash flows.

Variable Interest Entities. In June 2009, the FASB issued authoritative guidance related to variable interest entities which changes how a reporting entity determines when an entity that is insufficiently capitalized or is not controlled through voting rights should be consolidated and modifies the approach for determining the primary beneficiary of a variable interest entity. This guidance will require a reporting entity to provide additional disclosures about its involvement with variable interest entities and any significant changes in risk exposure due to that involvement. The guidance related to variable interest entities was effective on January 1, 2010 and did not have an impact on our consolidated financial position, results of operations or cash flows.

Off-Balance Sheet Arrangements
 
At December 31, 2010, we did not have any off-balance sheet arrangements.
 
Forward-Looking Statements
 
This report includes “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 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:
 
the supply and demand for natural gas and oil;
 
 
the price of oil and natural gas;

general economic conditions, either internationally, nationally or in jurisdictions where we conduct business;

conditions in the energy and financial markets;

our ability to obtain credit and/or capital in desired amounts and/or on favorable terms;

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;

failure of our joint interest partners to fund any or all of their portion of any capital program;

 
the occurrence of property acquisitions or divestitures;

reserve levels;

inflation;

competition in the oil and natural gas industry;

the availability and cost of relevant raw materials, goods and services;

the availability and cost of processing and transportation;

changes or advances in technology;

potential reserve revisions;
 
 
future processing volumes and pipeline throughput constraints;
 
 
developments in oil-producing and natural gas-producing countries;
 
 
drilling and exploration risks;

legislative initiatives and regulatory changes potentially adversely impacting our business and industry, including, but not limited to,  changes relating to national healthcare, cap and trade, hydraulic fracturing, state and federal corporate income taxes, retroactive royalty or production tax regimes, environmental regulations and environmental risks and liability under federal, state and local environmental laws and regulations;

effects of the application of applicable laws and regulations, including changes in such regulations or the interpretation thereof;

present and possible future claims, litigation and enforcement actions;

lease termination due to lack of activity or other disputes with mineral lease and royalty owners, whether regarding calculation and payment of royalties or otherwise;

the weather, including the occurrence of any adverse weather conditions and/or natural disasters affecting our business; and

any other factors that impact or could impact the exploration of oil or natural gas resources, including but not limited to the geology of a resource, the total amount and costs to develop recoverable reserves, legal title, regulatory, natural gas administration, marketing and operational factors relating to the extraction of oil and natural gas.
 
Item 7A.  Quantitative and Qualitative Disclosures about Market Risk
 
The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonable possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.  See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources - Commodity Price Risk, Interest Rate Risk and Related Hedging Activities.”
 
Commodity Price Risk. Our major market risk exposure is in the pricing of our oil, natural gas and NGL production. Realized pricing is primarily driven by the prevailing price for crude oil and spot market prices applicable to our U.S. natural gas and NGL production. Pricing for oil, natural gas and NGL production has been volatile and unpredictable for several years and we expect this volatility to continue in the future. Accordingly, we use certain derivative instruments, including fixed price swaps, basis swaps, costless collars and put options.  Although not risk free, we believe these activities will reduce commodity price fluctuations and thereby enable us to achieve a more predictable cash flow.
 
Our fixed price swap agreements are used to fix the sales price for our anticipated future natural gas and NGL production. Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument. These instruments are settled monthly. When the floating price exceeds the fixed price for a contract month, we pay our counterparty. When the fixed price exceeds the floating price, our counterparty is required to make a payment to us. We have designated these swaps as cash flow hedges.  We also have the ability to enter into fixed price swap agreements to fix the sales price for our anticipated future oil production.  Should this type of arrangement become attractive, we may enter into these types of agreements in the future.
 
Our costless collar agreements are used to fix the sales price within a floor price and ceiling price for our anticipated future oil and natural gas production.  Upon settlement, we receive a fixed price for the hedged commodity and pay our counterparty a floating market price, as defined in each instrument.  These instruments are settled when required as defined in each instrument.  When the floating market price exceeds the ceiling price, we pay our counterparty.  When the floor price exceeds the floating market price, our counterparty is required to make payment to us.  If the floating market price is within the floor and ceiling prices, no payments are required by either the Company or the counterparties.  We have designated these costless collars as cash flow hedges.  We also have the ability to enter into costless collar agreements to fix the sales price within a floor price and ceiling price for our anticipated future NGL production.  Should this type of arrangement become attractive, we may enter into these types of agreements in the future.
 
As of December 31, 2010, we had open natural gas derivative hedges in an asset position with a fair value of $28.6 million. A 10% increase in natural gas prices would reduce the fair value by approximately $8.9 million, while a 10% decrease in natural gas prices would increase the fair value by approximately $9.3 million. The effects of these derivative transactions on our natural gas sales are discussed above under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues – Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 – Natural Gas.”

As of December 31, 2010, we had open crude oil derivative hedges in a liability position with a fair value of $4.9 million. A 10% increase in crude oil prices would reduce the fair value by approximately $10.8 million, while a 10% decrease in crude oil prices would increase the fair value by approximately $8.6 million. The effects of these derivative transactions on our crude oil sales are discussed above under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Revenues – Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 – Crude Oil”.
 
As of December 31, 2010, we had open NGL derivative hedges in a liability position with a fair value of $4.0 million. A 10% increase in NGL prices would reduce the fair value by approximately $2.6 million, while a 10% decrease in NGL prices would increase the fair value by approximately $2.6 million. The effects of these derivative transactions on our NGL sales are discussed above under Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations – Revenues – Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 – NGLs”.

These fair value changes assume volatility based on prevailing market parameters at December 31, 2010.

Our current cash flow hedge positions are with counterparties who are lenders in our credit facilities.  Based upon communications with these counterparties, we expect the obligations under these transactions to continue to be met. We evaluated nonperformance risk using current credit default swap values and default probabilities for each counterparty and determined the impact to the fair value of our derivative assets at December 31, 2010 was insignificant.  We currently do not know of any circumstances that would limit access to our credit facilities or require a change in our debt or hedging structure.
 
At December 31, 2010, we had the following financial fixed price swap and costless collar transactions outstanding with associated notional volumes and average underlying prices that represent hedged prices of commodities at various market locations:

Product
Settlement
Period
Derivative
Instrument
Hedge
Strategy
 
Notional Daily Volume
MMBtu
   
Total of Notional Volume
MMBtu
   
Average Floor/Fixed Prices per
MMBtu
   
Average Ceiling Prices per MMBtu
   
Fair Market Value
Asset/(Liability)
(In thousands)
 
Natural Gas
2011
Swap
Cash flow
    15,000       5,475,000     $ 5.90     $ -     $ 8,472  
Natural Gas
2011
Costless Collar
Cash flow
    35,000       12,775,000       5.79       7.27       16,488  
Natural Gas
2012
Costless Collar
Cash flow
    10,000       3,660,000       5.75       7.15       3,613  
                    21,910,000                     $ 28,573  

 
Product
Settlement
Period
Derivative
Instrument
Hedge
Strategy
 
Notional Daily Volume
Bbl
   
Total of Notional Volume
Bbl
   
Average Floor/Fixed Prices per
Bbl
   
Average Ceiling Prices per Bbl
   
Fair Market Value
Asset/(Liability)
(In thousands)
 
Crude Oil
2011
Costless Collar
Cash flow
    2,300       839,500     $ 73.26     $ 99.96     $ (3,066 )
Crude Oil
2012
Costless Collar
Cash flow
    2,100       768,600       75.00       104.61       (1,837 )
                    1,608,100                     $ (4,903 )

 
Product
Settlement
Period
Derivative
Instrument
Hedge
Strategy
 
Notional Daily Volume
Bbl
   
Total of Notional Volume
Bbl
   
Average Floor/Fixed Prices per
Bbl
   
Average Ceiling Prices per Bbl
   
Fair Market Value
Asset/(Liability)
(In thousands)
 
NGL - Propane
2011
Swap
Cash flow
    350       127,750     $ 41.92     $ -     $ (1,237 )
NGL - Isobutane
2011
Swap
Cash flow
    110       40,150     $ 56.18     $ -     $ (490 )
NGL - Normal Butane
2011
Swap
Cash flow
    100       36,500     $ 54.81     $ -     $ (477 )
NGL - Pentane Plus
2011
Swap
Cash flow
    140       51,100     $ 70.61     $ -     $ (914 )
NGL - Propane
2012
Swap
Cash flow
    250       91,500     $ 42.84     $ -     $ (474 )
NGL - Isobutane
2012
Swap
Cash flow
    50       18,300     $ 61.95     $ -     $ (82 )
NGL - Normal Butane
2012
Swap
Cash flow
    50       18,300     $ 60.90     $ -     $ (78 )
NGL - Pentane Plus
2012
Swap
Cash flow
    100       36,600     $ 79.28     $ -     $ (261 )
                    420,200                     $ (4,013 )

Subsequent to December 31, 2010, we entered into additional hedging transactions to hedge portions of our expected future natural gas, crude oil and NGL production, excluding the ethane component of the NGL barrel.  See Item 8. “Financial Statements and Supplementary Data, Note 18 – Subsequent Events.”

Interest Rate Risk. Borrowings under our Restated Revolver mature on July 1, 2012 and bear interest at a LIBOR-based rate. To mitigate our exposure to rising interest rates, we entered into a series of interest rate swap agreements through December 2010.  We may enter into additional interest rate swap agreements in the future to mitigate interest rate risk if the costs are not prohibitive.
 
 
41

 

Item 8.  Financial Statements and Supplementary Data

Index to Financial Statements


   
Page
Report of Independent Registered Public Accounting Firm
 
43
Consolidated Balance Sheet as of December 31, 2010 and 2009
 
44
Consolidated Statement of Operations for the years ended December 31, 2010, 2009 and 2008
 
45
Consolidated Statement of Cash Flows for the years ended December 31, 2010, 2009 and 2008
 
46
Consolidated Statement of Stockholders' Equity for the years ended December 31, 2010, 2009 and 2008
 
47
Notes to Consolidated Financial Statements
 
48

 
Report of Independent Registered Public Accounting Firm


To the Board of Directors
and Stockholders of Rosetta Resources Inc.

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of operations, of cash flows and of stockholders' equity present fairly, in all material respects, the financial position of Rosetta Resources Inc. and its subsidiaries (the "Company") at December 31, 2010 and 2009, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2010 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company's management is responsible for these financial statements, for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on these financial statements and on the Company's internal control over financial reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

As discussed in Note 2, at December 31, 2009 the Company changed the manner in which its oil and gas reserves are estimated as well as the manner in which prices are determined to calculate the ceiling limit on capitalized oil and gas costs.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ PricewaterhouseCoopers LLP


Houston, Texas
February 25, 2011

 
Item 8.  Financial Statements and Supplementary Data

Rosetta Resources Inc.
Consolidated Balance Sheet
(In thousands, except par value and share amounts)