Attached files

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EX-23.1 - EX-23.1 - NEWFIELD EXPLORATION CO /DE/h79749exv23w1.htm
EX-32.1 - EX-32.1 - NEWFIELD EXPLORATION CO /DE/h79749exv32w1.htm
EX-31.1 - EX-31.1 - NEWFIELD EXPLORATION CO /DE/h79749exv31w1.htm
EX-21.1 - EX-21.1 - NEWFIELD EXPLORATION CO /DE/h79749exv21w1.htm
EX-32.2 - EX-32.2 - NEWFIELD EXPLORATION CO /DE/h79749exv32w2.htm
EX-31.2 - EX-31.2 - NEWFIELD EXPLORATION CO /DE/h79749exv31w2.htm
EX-24.1 - EX-24.1 - NEWFIELD EXPLORATION CO /DE/h79749exv24w1.htm
EX-10.32 - EX-10.32 - NEWFIELD EXPLORATION CO /DE/h79749exv10w32.htm
EX-10.30 - EX-10.30 - NEWFIELD EXPLORATION CO /DE/h79749exv10w30.htm
EX-10.28 - EX-10.28 - NEWFIELD EXPLORATION CO /DE/h79749exv10w28.htm
EX-10.33 - EX-10.33 - NEWFIELD EXPLORATION CO /DE/h79749exv10w33.htm
EX-10.31 - EX-10.31 - NEWFIELD EXPLORATION CO /DE/h79749exv10w31.htm
EX-10.29 - EX-10.29 - NEWFIELD EXPLORATION CO /DE/h79749exv10w29.htm
EX-10.27 - EX-10.27 - NEWFIELD EXPLORATION CO /DE/h79749exv10w27.htm
EX-10.25 - EX-10.25 - NEWFIELD EXPLORATION CO /DE/h79749exv10w25.htm
Table of Contents

 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
 
     
þ
  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
    For the transition period from          to          .
 
Commission file number: 1-12534
 
Newfield Exploration Company
(Exact name of registrant as specified in its charter)
 
     
Delaware
  72-1133047
(State of incorporation)   (I.R.S. Employer
Identification No.)
     
363 North Sam Houston Parkway East,
Suite 100,
Houston, Texas
(Address of principal executive offices)
  77060
(Zip Code)
 
Registrant’s telephone number, including area code:
(281) 847-6000
 
Securities Registered Pursuant to Section 12(b) of the Act:
 
     
Title of Each Class
 
Name of Each Exchange on Which Registered
 
Common Stock, par value $0.01 per share   New York Stock Exchange
 
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 þ     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 þ
 
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 þ     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) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ     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 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. (Check one):
 
             
Large accelerated filer þ
  Accelerated filer o   Non-accelerated filer o
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes o     No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $6.5 billion as of June 30, 2010 (based on the last sale price of such stock as quoted on the New York Stock Exchange).
 
As of February 22, 2011, there were 134,336,678 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
 
Documents incorporated by reference: Proxy Statement of Newfield Exploration Company for the Annual Meeting of Stockholders to be held May 5, 2011, which is incorporated by reference to the extent specified in Part III of this Form 10-K.
 
 


Table of Contents

 
TABLE OF CONTENTS
 
             
        Page
 
    1  
      2  
   
  Overview
    2  
   
  Strategy
    2  
        3  
        4  
   
  Reserves
    6  
        11  
        12  
        13  
        14  
   
  Marketing
    14  
        14  
   
  Employees
    14  
        14  
        19  
      21  
      29  
      29  
      29  
    30  
 
PART II
      31  
        31  
   
  Dividends
    31  
        31  
        32  
      33  
      34  
   
  Overview
    34  
        35  
        41  
        44  
        46  
        48  
        49  
        49  
        54  
        55  


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Table of Contents

             
        Page
 
      56  
        56  
        56  
        56  
      57  
      106  
      106  
        106  
        106  
        106  
      106  
 
PART III
      107  
        107  
        107  
      107  
      107  
      107  
      107  
 
PART IV
      108  
        108  
        108  
   
  Exhibits
    108  
 EX-10.25
 EX-10.27
 EX-10.28
 EX-10.29
 EX-10.30
 EX-10.31
 EX-10.32
 EX-10.33
 EX-21.1
 EX-23.1
 EX-24.1
 EX-31.1
 EX-31.2
 EX-32.1
 EX-32.2


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Table of Contents

 
If you are not familiar with any of the oil and gas terms used in this report, we have provided explanations of many of them under the caption “Commonly Used Oil and Gas Terms” at the end of Items 1 and 2 of this report. Unless the context otherwise requires, all references in this report to “Newfield,” “we,” “us” or “our” are to Newfield Exploration Company and its subsidiaries. Unless otherwise noted, all information in this report relating to oil and gas reserves and the estimated future net cash flows attributable to those reserves are based on estimates we prepared and are net to our interest.
 
Forward-Looking Information
 
This report contains information that is forward-looking or relates to anticipated future events or results, such as planned capital expenditures, the availability and sources of capital resources to fund capital expenditures and other plans and objectives for future operations. Although we believe that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including:
 
  •  oil and gas prices;
 
  •  general economic, financial, industry or business conditions;
 
  •  the impact of legislation and governmental regulations;
 
  •  the impact of regulatory approvals;
 
  •  the availability and cost of capital to fund our operations and business strategies;
 
  •  the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us;
 
  •  the availability of transportation and refining capacity for the crude oil we produce from our Monument Butte field;
 
  •  drilling results;
 
  •  the prices of goods and services;
 
  •  the availability of drilling rigs and other support services;
 
  •  labor conditions;
 
  •  weather conditions, and changes in weather patterns, including adverse conditions and changes in patterns due to climate change;
 
  •  environmental liabilities that are not covered by an effective indemnity or insurance;
 
  •  changes in tax rates;
 
  •  changes in estimates of reserves;
 
  •  the effect of worldwide energy conservation measures;
 
  •  the price and availability of, and demand for, competing energy sources; and
 
  •  the other factors affecting our business described below under the caption “Risk Factors.”
 
All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. See Items 1 and 2, “Business and Properties,” Item 1A, “Risk Factors,” Item 3, “Legal Proceedings,” Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A, “Quantitative and Qualitative Disclosures About Market Risk” for additional information about factors that may affect our businesses and operating results. These factors are not necessarily all of the important factors that could affect us. Use caution and common sense when considering these forward-looking statements. Unless securities laws require us to do so, we do not undertake any obligation to publicly correct or update any forward-looking statements, whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.


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We are an independent oil and gas company engaged in the exploration, development and acquisition of oil and gas properties. Our domestic areas of operation include the Mid-Continent, the Rocky Mountains, onshore Texas, Appalachia and the Gulf of Mexico. Internationally, we are also active in Malaysia and China.
 
General information about us can be found at www.newfield.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K, as well as any amendments and exhibits to those reports, are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the Securities and Exchange Commission, or the SEC. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
 
Overview
 
We are a Delaware corporation and were founded in 1989. Our company began as a Gulf of Mexico focused company. Over the last decade, we have diversified our asset base and added multiple areas capable of sustainable growth. Our asset base and related capital programs are diversified both geographically and by type — onshore and offshore, domestic and international, and conventional plays and unconventional “resource” plays in both oil and gas basins. Approximately 82% of our proved reserves and 90% of our probable reserves at year-end 2010 were located in resource plays, primarily in the Mid-Continent and the Rocky Mountains. Approximately 60% of our 2010 capital investments were allocated to growth opportunities in these regions. We expect our 2011 investment levels in these areas to be similar.
 
At year-end 2010, we had proved reserves of 3.7 Tcfe, a 3% increase over proved reserves at year-end 2009. At the end of 2010, our proved reserves were 67% natural gas and 58% proved developed. Our probable reserves were 74% natural gas. As a result of our focus on resource plays, our year-end 2010 proved reserve life index was approximately 13 years. Our 2010 production was 288 Bcfe.
 
         
2010 Proved Reserves by Area   2010 Probable Reserves by Area   2011 Estimated Production by Area
 
[PIE CHART]   [PIE CHART]   [PIE CHART]
3.7 Tcfe
  2.5 Tcfe   312-323 Bcfe
 
Strategy
 
Our growth strategy has evolved since our company was founded in 1989 and has allowed us to move into new unconventional plays, lengthen our reserves life and build a diverse portfolio capable of sustainable future growth. Our strategy today consists of the following key elements:
 
  •  focusing on unconventional, domestic resource plays of scale, characterized by large acreage positions and deep inventories of low risk drilling opportunities;
 
  •  growing reserves through an active drilling program, supplemented with select acquisitions;
 
  •  focusing on select geographic areas and allocating capital to the best growth opportunities;
 
  •  controlling operations and costs; and
 
  •  attracting and retaining a quality workforce through equity ownership and other performance-based incentives.
 
Focus on Unconventional Resource Plays of Scale.  Over the last several years, our industry has increased its focus on unconventional resources. These plays cover large acreage positions and have years of lower-risk drilling opportunities. Their development allows for efficiency gains in the drilling and completion


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processes, as well as sustainable and repeatable growth profiles. Our unconventional resource plays include producing positions in the Woodford Shale of Oklahoma, the Granite Wash of Texas and Oklahoma, the Uinta Basin of Utah and the Eagle Ford and Pearsall shales of southwest Texas. We also have acreage in the Marcellus Shale of Pennsylvania and the Southern Alberta Basin of Montana.
 
Drilling Program.  The components of our drilling program reflect the significant changes in our asset base over the last few years. To manage the risks associated with our strategy to grow reserves through our drilling programs, a substantial majority of the wells we drilled in 2010 were lower-risk with low to moderate reserve potential. We have lower-risk drilling opportunities in the Mid-Continent, the Rocky Mountains and the shallow waters of Malaysia. In addition, we have assessment drilling in areas like the Eagle Ford and Pearsall shales and the Southern Alberta Basin. These opportunities are complemented with higher-risk, higher reserve potential exploration plays in the deepwater of the Gulf of Mexico and international. We actively look for new drilling ideas on our existing property base and on properties that may be acquired.
 
Acquisitions.  Acquisitions have consistently been a part of our strategy, particularly when entering new geographic regions. Since 2000, we have completed five significant acquisitions that led to the establishment of new focus areas onshore in the United States. We actively pursue acquisitions of proved oil and gas properties in select geographic areas, including those areas where we currently focus. The potential to add reserves through drilling is a critical consideration in our acquisition screening process.
 
Geographic Focus.  We believe that our long-term success requires extensive knowledge of the geologic and operating conditions in the areas where we operate. Because of this belief, we focus our efforts on a limited number of geographic areas where we can use our core competencies and have a significant influence on operations. Geographic focus also allows more efficient use of capital and personnel.
 
Control of Operations and Costs.  In general, we prefer to operate our properties. By controlling operations, we can better manage production performance, control operating expenses and capital expenditures, consider the application of technologies and influence timing. At year-end 2010, we operated a significant portion of our net total production.
 
Equity Ownership and Incentive Compensation.  We want our employees to act like owners, so we reward and encourage them through equity ownership and performance-based compensation. A large portion of our employees’ compensation is tied to our performance.
 
2011 Outlook and Capital Investments
 
Our 2011 capital budget is $1.7 billion, excluding $170 million of capitalized interest and overhead. Approximately two-thirds of our capital investments will be allocated to oil projects and substantially all of the remainder is planned for “liquids rich” gas plays. We expect our 2011 production to grow 8-12% over 2010 levels. Domestic oil production is expected to increase about 50% in 2011. Natural gas production is expected to remain relatively flat in 2011, despite a significant reduction in natural gas investments. Our diversified portfolio of assets provides us with flexibility in our capital allocation process. We have the operational flexibility to react quickly with our capital expenditures to changes in our cash flows from operations or to commodity price volatility.
 
Our estimated 2011 capital investments by area are shown in the chart below:
 
[PIE CHART]
$1.7 Billion
 
Approximately 70% of our expected 2011 domestic oil and gas production is hedged. For a complete discussion of our hedging activities, a listing of open contracts as of December 31, 2010 and the estimated fair value of these contracts as of that date, see Note 4, “Derivative Financial Instruments,” to our consolidated financial statements.


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Table of Contents

 
Our Properties and Plans for 2011
 
Resource Plays
 
A key element of our strategy is to focus on domestic, unconventional resource plays of scale. These plays represent approximately 82% of our proved reserves and 90% of our probable reserves at year-end 2010.
 
Mid-Continent.  Our largest division in terms of our recent production, reserves and capital investment is the Mid-Continent. We are focused primarily in the Anadarko and Arkoma basins. In 2010, activity began to slow due to our shift from natural gas directed drilling to oil directed drilling throughout the Company. As of December 31, 2010, we owned a working interest in approximately 755,000 gross acres (approximately 410,000 net acres) and approximately 2,900 gross producing wells.
 
Woodford Shale.  Our largest single investment area over the last several years has been the Woodford Shale, located in the Arkoma Basin of southeast Oklahoma. The Woodford is primarily a dry gas shale formation that varies in thickness from 100 to 200 feet throughout our acreage. Our activity levels in the natural gas portion of the Woodford were reduced in 2010. We entered 2010 with eight rigs running and exited the year with three rigs. At year-end 2010, we owned an interest in approximately 172,000 net acres. Our average working interest is approximately 60%. Since entering the play in 2003, we have drilled more than 100 vertical wells and approximately 350 horizontal wells. In 2010, we assessed a new “oily” play in the Woodford, located primarily on the western edge of our acreage. We plan to drill additional wells in this play during 2011. In total, we plan to run two to three rigs in the Woodford during 2011.
 
Our 2010 production in the Woodford Shale was 25% higher than our 2009 production and as of December 31, 2010, our operated production was 169 MMcfe/d net.
 
We expect our natural gas production in the Woodford Shale to decline slightly in 2011 due to reduced capital investment in both our operated and non-operated drilling programs. Substantially all of our acreage is held-by-production. Our development plans for the field include drilling several thousand wells on primarily 40-acre spacing. In 2010, we continued to advance and improve this play through the drilling of longer lateral wells, repeatable drilling efficiency gains and optimization of completions. Our average lateral length increased by 25% in 2010 to approximately 6,300 feet which included several wells in excess of 10,000 feet. In 2011, we expect our average lateral length to be approximately 8,000 feet.
 
Granite Wash.  We are active in the Granite Wash play located in the Anadarko Basin of northern Texas and western Oklahoma and have more than 48,000 net acres in the play. Our largest producing field in the Granite Wash is Stiles/Britt Ranch, where we operate and own an average 75% working interest. Although we have approximately 150 producing vertical wells in Stiles/Britt Ranch, our drilling program is now dedicated to horizontal drilling. Since late 2008, we have drilled and completed 35 horizontal wells in the Granite Wash and the average initial production for these wells was approximately 16 MMcfe/d gross. During 2010, we ran three to four operated drilling rigs in the field with total daily production as of December 31, 2010 of approximately 86 MMcfe/d net. We expect to continue this level of activity in the Granite Wash, and expect our production to grow nearly 20% in 2011. We have an inventory of approximately 300 potential drilling locations in the Granite Wash.
 
Rocky Mountains.  As of December 31, 2010, we owned an interest in approximately 1.2 million gross acres (850,000 net acres) and more than 2,000 gross producing wells. Our assets are primarily oil and characterized by long-lived production. Our efforts today are focused primarily in the Uinta, Williston and Southern Alberta basins.
 
Greater Monument Butte.  Our largest asset in the Rocky Mountains is the Greater Monument Butte field area, located in the Uinta Basin of Utah. Our working interest in the region averages about 71%. We have approximately 1,200 productive oil wells in the Monument Butte Unit. Our acreage in this region is approximately 183,000 net acres. This includes over 60,000 net acres that we have added in recent years on Tribal and fee acreage north and adjacent to the Monument Butte Unit. Since 2008, we have drilled over 300 wells on the Tribal and fee acreage. Our gross production from the Greater Monument Butte field area has grown from 7,000 BOPD in 2004 to a 2010 exit rate of approximately 22,000 BOPD. In 2011, we are


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planning to continue drilling a substantial portion of the acreage on 20-acre development spacing and estimate that we have thousands of remaining locations in the Greater Monument Butte field area.
 
There is a significant gas resource beneath the shallow producing oil zones at Monument Butte. In 2008, we participated in the drilling of six successful deep test wells to evaluate these deeper formations.
 
Williston Basin/Southern Alberta Basin.  We have approximately 120,000 net acres in the Williston Basin, excluding approximately 54,000 net acres in the mature Elm Coulee field. To date, we have drilled 44 successful wells with production from the Bakken and Sanish/Three Forks formations. In late 2010, we released information on two super extended 9,000 foot lateral wells (SXLs) west of the Nesson Anticline with 24 hour initial production rates averaging more than 3,300 BOEPD gross. In 2011, virtually all of our wells within our Williston Basin drilling program are expected to be SXL wells. Our production at year-end 2010 was approximately 7,000 BOEPD net. We plan to run four to six operated rigs in the Williston Basin in 2011. In late 2009, we reached an agreement with the Blackfeet Nation covering approximately 156,000 net acres in the Southern Alberta Basin of northern Montana. Including this transaction, we now have approximately 280,000 net acres in the Southern Alberta Basin. In 2010, we drilled five vertical wells and one horizontal well and assessment continues in 2011.
 
Green River Basin.  We own interests and operate our activities on approximately 3,000 net acres in the Pinedale field, located in Sublette County, Wyoming. We also have an interest in the Jonah field, located in Sublette County, Wyoming. Although we halted our activities in the Green River Basin in 2009 due to lower gas prices, we see the potential to drill additional locations as gas prices improve in the future.
 
Onshore Texas.  We have approximately 335,000 net acres in the Eagle Ford and Pearsall shales in the Maverick Basin, located in Maverick, Dimmit and Zavala counties, Texas. The acreage is prospective for multiple geologic horizons. Our initial assessment program in 2010 included 11 Eagle Ford Shale wells with lateral lengths of approximately 5,000 feet. The wells encountered light oil with API gravities ranging from 30 to 50 degrees. We now believe that substantially all of our Eagle Ford acreage in the Maverick Basin is within the oil window.
 
Appalachia.  In mid-2009, we signed a joint exploration agreement with Hess Corporation covering acreage primarily in Wayne County, Pennsylvania. We are the operator of this venture with a 50% working interest. At year-end 2010, we had leased about 35,000 net acres. This marked our entry into the Marcellus — one of the nation’s largest resource plays. The Marcellus is economically advantaged due to its close proximity to the gas markets in the northeast. To date, we have drilled three vertical geologic test wells and are currently evaluating the data. These wells have not been completed. We remain interested in the Appalachia region and continue to look for attractive opportunities to increase our ownership in the trend.
 
Conventional Plays
 
We also have operations in conventional plays onshore Texas, in the Gulf of Mexico and offshore Malaysia and China.
 
Onshore Texas.  As of December 31, 2010, we owned an interest in approximately 307,000 gross acres (195,000 net) and about 640 gross producing wells onshore Texas. In 2010, we slowed our activities in many of our conventional natural gas plays in response to lower natural gas prices. At year-end 2010, we were producing approximately 125 MMcfe/d net from our conventional onshore Texas assets. With planned decreased investments in 2011 and natural field declines, we expect production from this area to decline approximately 20% during 2011. In late 2010, we began a process to monetize certain non-strategic assets primarily from our onshore Texas region.
 
Gulf of Mexico.  Our Gulf of Mexico operations are focused on the deepwater. At year-end 2010, our production from the Gulf of Mexico was approximately 95 MMcfe/d net. In addition to our producing fields, we have three developments underway. As of December 31, 2010, we owned interests in 84 deepwater leases and approximately 350,000 net acres. We have an inventory of prospects acquired primarily through federal lease sales. Our working interests typically range from 20 to 50%. Following the 2010 Macondo incident in the Gulf of Mexico, we elected to defer our 2011 exploratory plans in the deepwater Gulf. With two deepwater developments


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commencing production in 2011, we expect our Gulf of Mexico production to grow approximately 8% compared to 2010.
 
International.  Our international activities are focused in Southeast Asia. We have production and active developments offshore Malaysia and China. Our international production at year-end 2010 was approximately 19,000 BOPD net. We have an interest in approximately 2.5 million gross acres (936,000 net) offshore Malaysia and approximately 404,000 gross acres (385,000 net) offshore China. In 2011, our plans include continued development of our oil fields offshore Malaysia. During 2011, we also plan to develop our “Pearl” discovery (initial production 2013) in the Pearl River Mouth Basin of China and drill up to two exploratory wells offshore China. We expect our international production to grow moderately in 2011.
 
Reserves
 
Concentration
 
Reserves Concentration.  The table below sets forth the concentration of our proved and probable reserves, by location, and the percentage of those reserves attributable to our largest fields. Our largest fields, the Woodford Shale and Monument Butte, accounted for about 50% of the total net present value of our proved reserves at December 31, 2010.
 
                 
    Percentage of
  Percentage of
    Proved Reserves   Probable Reserves
 
Located domestically
    94       95  
Located onshore
    91       93  
10 largest fields
    85       96  
2 largest fields
    61       79  
 
Largest Fields.  The table below sets forth for our largest fields (those whose reserves are greater than 15% of our total proved reserves) the annual production volumes, average realized prices and related production cost structure on a per unit of production basis. For a discussion regarding our total domestic and international annual production volumes, average realized prices and related production cost structure on a per unit of production basis, see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations.”
 
                         
    Year Ended December 31,
    2010   2009   2008
 
Production:
                       
Natural gas (Bcf):
                       
Monument Butte
    5.6       4.5       5.1  
Woodford Shale
    76.8       61.4       52.1  
Oil and condensate (MBbls):
                       
Monument Butte
    4,670       4,080       3,471  
Woodford Shale
    71       37       10  
Average Realized Prices:
                       
Natural gas (per Mcf):
                       
Monument Butte
  $ 4.16     $ 2.80     $ 3.62  
Woodford Shale
  $ 3.86     $ 3.19     $ 6.66  
Oil and condensate (per Bbl):
                       
Monument Butte
  $ 65.26     $ 48.21     $ 81.48  
Woodford Shale
  $ 74.23     $ 53.49     $ 97.23  
Production Cost:
                       
Monument Butte (per BOE)
  $ 8.91     $ 7.65     $ 9.66  
Woodford Shale (per Mcfe)
  $ 0.94     $ 0.82     $ 1.06  


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Estimated Reserves
 
All reserve information in this report is based on estimates prepared by our petroleum engineering staff and is the responsibility of management. The preparation of our oil and gas reserves estimates is completed in accordance with our prescribed internal control procedures, which include verification of data input into reserves forecasting and economics evaluation software, as well as multi-discipline management reviews, as described below. The technical employee responsible for overseeing the preparation of the reserves estimates has a Bachelor of Science in Petroleum Engineering, with more than 25 years of experience (including 15 years of experience in reserve estimation) and is a Registered Professional Engineer in Texas.
 
Our reserves estimates are made using available geological and reservoir data as well as production performance data. These estimates, made by our petroleum engineering staff, are reviewed annually with management and revised, either upward or downward, as warranted by additional data. The data reviewed includes, among other things, seismic data, well logs, production tests, reservoir pressures, individual well and field performance data. The data incorporated into our interpretations includes structure and isopach maps, individual well and field performance and other engineering and geological work products such as material balance calculations and reservoir simulation to arrive at conclusions about individual well and field projections. Additionally, offset performance data, operating expenses, capital costs and product prices factor into estimating quantities of reserves. Revisions are necessary due to changes in, among other things, reservoir performance, prices, economic conditions and governmental regulations, as well as changes in the expected recovery rates associated with infill drilling. Sustained decreases in prices, for example, may cause a reduction in some reserves due to reaching economic limits sooner.
 
Actual quantities of reserves recovered will most likely vary from the estimates set forth below. Reserves and cash flow estimates rely on interpretations of data and require assumptions that may be inaccurate. For a discussion of these interpretations and assumptions, see “Actual quantities of oil and gas reserves and future cash flows from those reserves will most likely vary from our estimates” under Item 1A of this report. Our estimates of proved reserves, proved developed reserves and proved undeveloped reserves and future net cash flows and discounted future net cash flows from proved reserves at December 31, 2010, 2009 and 2008 and changes in proved reserves during the last three years are contained in “Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Estimated Net Quantities of Proved Oil and Gas Reserves” in Item 8 of this report. For a discussion of the significant changes in our proved reserves during 2010, please see the information set forth in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Proved Reserves” in Item 7 of this report.


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The following table shows, by country and in the aggregate, a summary of our proved and probable oil and gas reserves as of December 31, 2010.
 
                         
    Oil and
    Natural
       
    Condensate     Gas     Total  
    (MMBbls)     (Bcf)     (Bcfe)(1)  
 
Proved Reserves
                       
Proved Developed Reserves:
                       
Domestic
    90       1,505       2,045  
International:
                       
Malaysia
    15             91  
China
    5             28  
                         
Total International
    20             119  
                         
Total Proved Developed
    110       1,505       2,164  
                         
Proved Undeveloped Reserves:
                       
Domestic
    80       987       1,462  
International:
                       
Malaysia
    13             78  
China
    1             8  
                         
Total International
    14             86  
                         
Total Proved Undeveloped
    94       987       1,548  
                         
Total Proved Reserves
    204       2,492       3,712  
                         
Probable Reserves
                       
Probable Developed Reserves:
                       
Domestic
    1       23       29  
International:
                       
Malaysia
    1             5  
China
                 
                         
Total International
    1             5  
                         
Total Probable Developed
    2       23       34  
                         
Probable Undeveloped Reserves:
                       
Domestic
    85       1,815       2,325  
International:
                       
Malaysia
    4             23  
China
    15             91  
                         
Total International
    19             114  
                         
Total Probable Undeveloped
    104       1,815       2,439  
                         
Total Probable Reserves
    106       1,838       2,473  
                         
 
 
(1) Billion cubic feet equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.


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Proved Reserves.  Our year-end 2010 proved reserves of 3,712 Bcfe increased 3% compared to our proved reserves at year-end 2009. Our reserves consisted of 1,783 Bcfe proved developed producing, 381 Bcfe proved developed non-producing and 1,548 Bcfe proved undeveloped reserves.
 
At December 31, 2009, our estimated proved undeveloped reserves were 1,708 Bcfe. During 2010, we spent $550 million of drilling, completion and facilities-related capital to convert 262 Bcfe of our December 31, 2009 proved undeveloped reserves into proved developed reserves. During 2010, we added 414 Bcfe of new proved undeveloped reserves through drilling activities. Proved undeveloped reserve quantities were limited by the activity level of development drilling we expect to undertake during the 2011-2015 five-year period. Due to the higher margins of oil over natural gas investments, we shifted significant capital toward oil projects in our portfolio. As a result of this shift, we reclassified approximately 315 Bcfe of proved undeveloped reserves (nearly all Mid-Continent natural gas reserves) to probable reserves because the slower pace of development activity placed them beyond the five-year development horizon. Quantities of reserves that would otherwise meet the definition of proved undeveloped reserves, except for the fact that they will be developed beyond the 2011-2015 five-year horizon (1,336 Bcfe), were classified as probable reserves, in accordance with SEC regulations. As a result of the foregoing and minor performance related revisions, our proved undeveloped reserves at December 31, 2010 were 1,548 Bcfe, 99.6% of which have been included in our reserve report for less than five years. For additional information regarding the changes in our proved reserves, see “Proved Reserves” under Item 7 of this report.
 
In the years 2008-2010, we developed 17%, 11% and 13%, respectively, of our prior year-end proved undeveloped reserves. The development plans in our year-end reserve report reflect (i) the allocation of capital to projects in the first year of activity based upon the initial budget for such year and (ii) in subsequent years, the capital allocation in our five-year business plan, each of which generally is governed by our expectations for capital investment in such time period. Changes in commodity pricing between the time of preparation of the reserve report and actual investment, investment alternatives that may have been added to our portfolio of assets, changes in the availability and costs of oilfield services, and other economic factors may lead to changes in our development plans. As a result, the future rate at which we develop our proved undeveloped reserves may vary from historical development rates.
 
Probable Reserves.  Our total estimated probable reserves of 2,473 Bcfe at December 31, 2010, consisted of 34 Bcfe of developed and 2,439 Bcfe of undeveloped reserves, as compared to probable developed and undeveloped reserves at year-end 2009 of 101 Bcfe and 1,792 Bcfe, respectively.
 
At December 31, 2009, our estimated probable reserves were 1,893 Bcfe. During 2010, we converted 315 Bcfe of our December 31, 2009 probable reserves into proved developed reserves. Also during 2010, we added probable reserves of 1,025 Bcfe, which included 706 Bcfe of additions from our exploration and development activities and the reclassification of 315 Bcfe from proved undeveloped reserves (nearly all Mid-Continent natural gas reserves) to probable undeveloped reserves. Performance related revisions of previous estimates reduced probable reserves by 147 Bcfe at December 31, 2010. As a result of the foregoing and minor pricing related revisions, our probable reserves at December 31, 2010 were 2,473 Bcfe.
 
Probable undeveloped reserves of 2,439 Bcfe at year-end 2010 include 1,336 Bcfe that would otherwise meet the definition of proved undeveloped reserves, except that they will not be developed during the 2011-2015 five-year horizon. The characteristic uncertainties associated with the remaining 1,103 Bcfe of undeveloped probable reserves vary significantly between our major operating areas. These uncertainties restrain this reserve classification from becoming proved reserves due to their cumulative effect on achieving the reasonable certainty threshold required for proved reserves. These additional uncertainties include the lack of 3-D seismic control, uncertainty associated with geologic and reservoir continuity with increasing distance away from a producing well, immature portions of an existing waterflood, secondary response in areas of a field that has exhibited lower primary waterflood recoveries, incremental recovery factors and field development timing associated with regulatory and/or governmental approval.


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Reserves Sensitivities.  To determine our year-end 2010 reserves estimates, we utilized the unweighted average first-day-of-the-month natural gas and crude oil prices for the prior twelve months, which was $4.38 per MMBtu and $79.42 per barrel, respectively, adjusted for market differentials.
 
The quantity of our proved reserves decreases slightly at lower crude oil prices as a result of shortening the economic life of our proved developed reserves. Our development plans would not materially change across a range of crude oil prices between $60 and $90 per barrel and, therefore, have little impact on the quantity of proved undeveloped reserves. That quantity is limited by the level of development drilling we expect to undertake during the 2011-2015 five-year period. Our proved undeveloped oil reserves are primarily in our Monument Butte field.
 
The quantity of our probable reserves changes less than 1% between a $4.00 and $5.00 per MMBtu natural gas price with no change in oil price. Using a $60 to $70 per barrel oil price range, with no change in natural gas price, the quantity of our probable reserves is relatively unchanged. Our probable reserves increase slightly at higher oil prices.
 
Under the terms of our production sharing contracts in Malaysia and China, an increase or decrease in realized oil prices would result in a decrease or increase, respectively, in our proved reserves. At higher oil prices, lesser quantities of oil are required for cost recovery and at lower oil prices, greater quantities of oil are required for cost recovery. Our share (the contractor’s share) of future production is impacted accordingly. The effect of higher or lower oil prices may be partially offset by extending or shortening, respectively, the economic life of proved reserves.


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Drilling Activity
 
The following table sets forth our drilling activity for each year in the three-year period ended December 31, 2010.
 
                                                 
    2010     2009     2008  
    Gross     Net     Gross     Net     Gross     Net  
 
Exploratory wells:
                                               
Domestic:
                                               
Productive(1)
    360       215.6       273       153.1       385       217.4  
Nonproductive(2)
    6       3.0       8       4.8       20       15.4  
International:
                                               
China:
                                               
Productive(3)
                1       1.0       2       1.1  
Nonproductive(4)
    2       2.0                   1       1.0  
Malaysia:
                                               
Productive(5)
    1       0.4       1       0.4       5       2.6  
Nonproductive(6)
    3       2.6                          
International Total:
                                               
Productive
    1       0.4       2       1.4       7       3.7  
Nonproductive
    5       4.6                   1       1.0  
                                                 
Exploratory well total
    372       223.6       283       159.3       413       237.5  
                                                 
Development wells:
                                               
Domestic:
                                               
Productive
    243       189.8       128       98.7       175       138.2  
Nonproductive
                            4       3.0  
International:
                                               
China:
                                               
Productive
    5       0.6       12       1.4       6       0.7  
Nonproductive
                            2       0.2  
Malaysia:
                                               
Productive
    7       4.3       5       2.8       7       4.2  
Nonproductive
    1       0.6                          
International Total:
                                               
Productive
    12       4.9       17       4.2       13       4.9  
Nonproductive
    1       0.6                   2       0.2  
                                                 
Development well total
    256       195.3       145       102.9       194       146.3  
                                                 
 
 
(1) Includes 126 gross (91.1 net), 29 gross (17.7 net) and 38 gross (27.1 net) wells in 2010, 2009 and 2008, respectively, that are not exploitation wells.
 
(2) Includes 6 gross (3.0 net), 3 gross (1.3 net) and 9 gross (7.5 net) wells in 2010, 2009 and 2008, respectively, that are not exploitation wells.
 
(3) Includes 1 gross (1.0 net) well in each of 2009 and 2008 that is not an exploitation well.
 
(4) Includes 2 gross (2.0 net) wells in 2010 that are not exploitation wells. The well in 2008 is not an exploitation well.
 
(5) Includes 1 gross (0.4 net), 1 gross (0.4 net) and 2 gross (1.1 net) wells in 2010, 2009 and 2008, respectively, that are not exploitation wells.
 
(6) Includes 2 gross (2.0 net) wells in 2010 that are not exploitation wells.
 
We were in the process of drilling 24 gross (15.4 net) exploratory wells (includes 19 gross (11.5 net) exploitation wells) and 3 gross (2.0 net) development wells domestically at December 31, 2010. Internationally, we were drilling 1 gross (0.1 net) exploratory well in China at December 31, 2010. This well is not an exploitation well.


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Productive Wells
 
The following table sets forth the number of productive oil and gas wells in which we owned an interest as of December 31, 2010 and the location of, and other information with respect to, those wells. As of December 31, 2010, we had 6 gross (6.0 net) gas wells and 5 gross (3.0 net) oil wells with multiple completions.
 
                                                 
    Company
    Outside
    Total
 
    Operated Wells     Operated Wells     Productive Wells  
    Gross     Net     Gross     Net     Gross     Net  
 
Domestic:
                                               
Offshore:
                                               
Oil
                4       1.0       4       1.0  
Natural gas
    6       3.8       3       0.9       9       4.7  
Onshore:
                                               
Oil
    2,343       1,887.6       702       76.1       3,045       1,963.7  
Natural gas
    1,723       1,361.3       1,455       309.4       3,178       1,670.7  
                                                 
Total Domestic:
                                               
Oil
    2,343       1,887.6       706       77.1       3,049       1,964.7  
Natural gas
    1,729       1,365.1       1,458       310.3       3,187       1,675.4  
                                                 
International:
                                               
Offshore China:
                                               
Oil
                35       4.2       35       4.2  
Offshore Malaysia:
                                               
Oil
    18       10.8       25       12.5       43       23.3  
                                                 
Total International:
                                               
Oil
    18       10.8       60       16.7       78       27.5  
                                                 
Total:
                                               
Oil
    2,361       1,898.4       766       93.8       3,127       1,992.2  
Natural gas
    1,729       1,365.1       1,458       310.3       3,187       1,675.4  
                                                 
Total
    4,090       3,263.5       2,224       404.1       6,314       3,667.6  
                                                 
 
The day-to-day operations of oil and gas properties are the responsibility of an operator designated under pooling or operating agreements or production sharing contracts. The operator supervises production, maintains production records, employs or contracts for field personnel and performs other functions. Generally, an operator receives reimbursement for direct expenses incurred in the performance of its duties as well as monthly per-well producing and drilling overhead reimbursement at rates customarily charged by unaffiliated third parties. The charges customarily vary with the depth and location of the well being operated.


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Acreage Data
 
As of December 31, 2010, we owned interests in developed and undeveloped oil and gas acreage set forth in the table below. Domestic ownership interests generally take the form of “working interests” in oil and gas leases that have varying terms. International ownership interests generally arise from participation in production sharing contracts.
 
                                 
    Developed
    Undeveloped
 
    Acres     Acres  
    Gross     Net     Gross     Net  
          (In thousands)        
 
Domestic:
                               
Offshore
    86       20       548       330  
Onshore:
                               
Mid-Continent
    624       351       131       60  
Rocky Mountains
    250       154       970       696  
Gulf Coast
    595       473       321       216  
Appalachia
                74       37  
                                 
Total Onshore
    1,469       978       1,496       1,009  
                                 
Total Domestic
    1,555       998       2,044       1,339  
                                 
International:
                               
Offshore China
    22       3       382       382  
Offshore Malaysia
    192       98       2,285       838  
                                 
Total International
    214       101       2,667       1,220  
                                 
Total
    1,769       1,099       4,711       2,559  
                                 
 
The table below summarizes by year and geographic area our undeveloped acreage scheduled to expire in the next five years. In most cases, the drilling of a commercial well, or the filing and approval of a development plan or suspension of operations, will hold acreage beyond the expiration date. We own fee mineral interests in 396,407 gross (107,246 net) undeveloped acres. These interests do not expire.
 
                                                                                         
    Undeveloped Acres Expiring        
    2011     2012     2013     2014     2015        
    Gross     Net     Gross     Net     Gross     Net     Gross     Net     Gross     Net        
    (In thousands)  
 
Domestic:
                                                                                       
Offshore
    11       7       57       18       76       70       40       20       6       3          
Onshore:
                                                                                       
Mid-Continent
    18       7       34       20       72       30       4       1       1       1          
Rocky Mountains
    163       102       57       45       47       29       50       32       60       32          
Gulf Coast
    103       52       66       55       23       17       11       6       1                
                                                                                         
Total Onshore
    284       161       157       120       142       76       65       39       62       33          
                                                                                         
Total Domestic
    295       168       214       138       218       146       105       59       68       36          
                                                                                         
International:
                                                                                       
Offshore China
                            382       382                                  
Offshore Malaysia
    1,098       443                   1,187       395                                  
                                                                                         
Total International
    1,098       443                   1,569       777                                  
                                                                                         
Total
    1,393       611       214       138       1,787       923       105       59       68       36          
                                                                                         


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Title to Properties
 
We believe that we have satisfactory title to all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, carried, net profits, working and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, ordinary course liens incidental to operating agreements and for current taxes, development obligations under oil and gas leases or capital commitments under production sharing contracts or exploration licenses. As is customary in the industry in the case of undeveloped properties, often little investigation of record title is made at the time of acquisition. More detailed title work and investigations are made prior to the consummation of any acquisition of producing properties and before any commencement of drilling operations on undeveloped properties.
 
Marketing
 
Substantially all of our oil and gas production is sold to a variety of purchasers under short-term (less than 12 months) contracts at market sensitive prices. For a list of purchasers of our oil and gas production that accounted for 10% or more of our consolidated revenue for the three preceding calendar years, please see Note 1, “Organization and Summary of Significant Accounting Policies — Major Customers,” to our consolidated financial statements. We believe that the loss of any of these purchasers would not have a material adverse effect on us because alternative purchasers are readily available with the exception of purchasers of our Monument Butte field oil production. Due to the higher paraffin content of this production, there is limited refining capacity for it. Please see the discussion under “There is limited transportation and refining capacity for our black wax crude oil, which may limit our ability to sell our current production or to increase our production at Monument Butte in the Uinta Basin” in Item 1A of this report.
 
Competition
 
Competition in the oil and gas industry is intense, particularly with respect to the hiring and retention of technical personnel, the acquisition of properties and access to drilling rigs and other services. For a further discussion, please see the information regarding competition set forth in Item 1A of this report.
 
Employees
 
As of February 22, 2011, we had 1,352 employees. All but 123 of our employees were located in the U.S. None of our employees are covered by a collective bargaining agreement. We believe that relationships with our employees are satisfactory.
 
Regulation
 
Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulations. An overview of these regulations is set forth below. We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the captions “We are subject to complex laws that can affect the cost, manner or feasibility of doing business” and “the potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.” under Item 1A of this report.
 
Federal Regulation of Sales and Transportation of Natural Gas.  Our sales of natural gas are affected directly and indirectly by the availability, terms and cost of natural gas transportation. The prices and terms for access to pipeline transportation of natural gas are subject to extensive federal and state regulation. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act (NGA) and by regulations and orders promulgated under the NGA by the FERC. In certain limited


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circumstances, intrastate transportation and wholesale sales of natural gas also may be affected directly or indirectly by laws enacted by Congress and by FERC regulations. The Outer Continental Shelf Lands Act, or OCSLA, requires that all pipelines operating on or across the shelf provide open-access, non-discriminatory service. There are currently no regulations implemented by the FERC under its OCSLA authority on gatherers and other entities outside the reach of its Natural Gas Act jurisdiction. Therefore, we do not believe that any FERC or BOEMRE action taken under OCSLA will affect us in a way that materially differs from the way it will affect other natural gas producers, gatherers and marketers with which we compete.
 
Pursuant to authority enacted in the Energy Policy Act of 2005 (2005 EPA), FERC has promulgated anti-manipulation regulations, violations of which make it unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC to use or employ any device, scheme, or artifice to defraud, to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity. Violation of this requirement, similar to violations of other NGA and FERC requirements, may be penalized by the FERC up to $1 million per day per violation. FERC may also order disgorgement of profit and corrective action. We believe, however, that neither the 2005 EPA nor the regulations promulgated by FERC as a result of the 2005 EPA will affect us in a way that materially differs from the way they affect other natural gas producers, gatherers and marketers with which we compete.
 
Our sales of natural gas and crude are also subject to requirements under the Commodity Exchange Act (CEA) and regulations promulgated thereunder by the Commodity Futures Trading Commission (CFTC). The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity.
 
The current statutory and regulatory framework governing interstate natural gas transactions is subject to change in the future, and the nature of such changes is impossible to predict. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC, the CFTC and the courts. The natural gas industry historically has been very heavily regulated. In the past, the federal government regulated the prices at which natural gas could be sold. Congress removed all price and non-price controls affecting wellhead sales of natural gas effective January 1, 1993. There is always some risk, however, that Congress may reenact price controls in the future. Changes in law and to FERC policies and regulations may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate pipelines, and we cannot predict what future action the FERC will take. Therefore, there is no assurance that the current regulatory approach recently pursued by the FERC and Congress will continue. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers, gatherers and marketers with which we compete.
 
Federal Regulation of Sales and Transportation of Crude Oil.  Our sales of crude oil and condensate are currently not regulated. In a number of instances, however, the ability to transport and sell such products are dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act. Certain regulations implemented by the FERC in recent years could result in an increase in the cost of transportation service on certain petroleum products pipelines. However, we do not believe that these regulations affect us any differently than other crude oil and condensate producers.
 
Federal Leases.  Many of our domestic oil and gas leases are granted by the federal government and administered by the BOEMRE or the BLM, both federal agencies. BOEMRE and BLM leases contain relatively standardized terms and require compliance with detailed BLM or BOEMRE regulations and, in the case of offshore leases, orders pursuant to OCSLA (which are subject to change by the BOEMRE). Many onshore leases contain stipulations that may limit activities that may be conducted on the lease. Some stipulations are unique to particular geographic areas and may limit the timing and manner in which certain activities may be conducted or, in some cases, may prescribe no surface occupancy. For offshore operations,


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lessees must obtain BOEMRE approval for exploration, development and production plans prior to the commencement of such operations. In addition to permits required from other agencies (such as the Coast Guard, the Army Corps of Engineers and the Environmental Protection Agency), lessees must obtain a permit from the BLM or the BOEMRE, as applicable, prior to the commencement of drilling, and comply with regulations governing, among other things, engineering and construction specifications for production facilities, safety procedures, plugging and abandonment of wells on the Shelf and removal of facilities. To cover the various obligations of lessees on the Shelf, the BOEMRE generally requires that lessees have substantial net worth or post bonds or other acceptable assurances that such obligations will be met. The cost of such bonds or other surety can be substantial and there is no assurance that bonds or other surety can be obtained in all cases. We are currently exempt from the supplemental bonding requirements of the BOEMRE. Under certain circumstances, the BLM or the BOEMRE, as applicable, may require that our operations on federal leases be suspended or terminated. Any such suspension or termination could materially and adversely affect our financial condition, cash flows and results of operations.
 
The BOEMRE regulations governing the calculation of royalties and the valuation of crude oil produced from federal leases provide that the BOEMRE will collect royalties based upon the market value of oil produced from federal leases. The 2005 EPA formalizes the royalty in-kind program of the BOEMRE, providing that the BOEMRE may take royalties in-kind if the Secretary of the Interior determines that the benefits are greater than or equal to the benefits that are likely to have been received had royalties been taken in value. We believe that the BOEMRE’s royalty in-kind program will not have a material effect on our financial position, cash flows or results of operations.
 
In 2006, the BOEMRE amended its regulations to require additional filing fees. The BOEMRE has estimated that these additional filing fees will represent less than 0.1% of the revenues of companies with offshore operations in most cases. We do not believe that these additional filing fees will affect us in a way that materially differs from the way they affect other producers, gatherers and marketers with which we compete.
 
State and Local Regulation of Drilling and Production.  We own interests in properties located onshore in a number of states and in state waters offshore Texas and Louisiana. These states regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of these states also govern a number of environmental and conservation matters, including the handling and disposing or discharge of waste materials, the size of drilling and spacing units or proration units and the density of wells that may be drilled, unitization and pooling of oil and gas properties and establishment of maximum rates of production from oil and gas wells. Some states have the power to prorate production to the market demand for oil and gas.
 
Environmental Regulations.  Our operations are subject to numerous laws and regulations relating to environmental protection, including the discharge of substances into the environment, and permitting for oil and gas activities before, during or after operations begin. The cost to comply can be significant and failure to comply with these laws and regulations may result in administrative, civil and criminal penalties, the imposition of remedial and damage payment obligations, or injunctive relief (including orders to cease operations). Environmental laws and regulations are complex, and have tended to become more stringent over time. Oil and gas activities, both onshore and offshore, in certain areas have been opposed by environmental groups through public comments on agency actions and through litigation. Moreover, some environmental laws and regulations may impose strict liability, which could subject us to liability for conduct that was lawful at the time it occurred or conduct or conditions caused by prior operators or third parties. Governmental action, through either legislative or administrative venues, that prohibits or restricts onshore or offshore drilling thereby changing the business climate under which we operate may result in increased costs to the oil and gas industry in general and our business and financial results could be adversely affected.
 
The Oil Pollution Act, or OPA, imposes regulations on “responsible parties” related to the prevention of oil spills and liability for damages resulting from spills in U.S. waters. A “responsible party” includes the


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owner or operator of an onshore facility, vessel or pipeline, or the lessee or permittee of the area in which an offshore facility is located. OPA assigns strict, joint and several liability to each responsible party for oil removal costs and a variety of public and private damages. While liability limits apply in some circumstances, a party cannot take advantage of such limits if the spill was caused by gross negligence or willful misconduct or resulted from violation of a federal safety, construction or operating regulation, or if the party fails to report a spill or to cooperate fully in the cleanup. Even if applicable, the liability limits for offshore facilities require the responsible party to pay all removal costs, plus up to $75 million in other damages for offshore facilities and up to $350 million for onshore facilities. Few defenses exist to the liability imposed by OPA. Failure to comply with ongoing requirements or inadequate cooperation during a spill event may subject a responsible party to administrative, civil or criminal enforcement actions.
 
OPA also requires operators in the Gulf of Mexico to demonstrate to the BOEMRE that they possess available financial resources that are sufficient to pay for costs that may be incurred in responding to an oil spill. Under OPA and implementing BOEMRE regulations, responsible parties are required to demonstrate that they possess financial resources sufficient to pay for environmental cleanup and restoration costs of at least $10 million for an oil spill in state waters and at least $35 million for an oil spill in federal waters.
 
In addition to OPA, our discharges to waters of the U.S. are further limited by the federal Clean Water Act, or CWA, and analogous state laws. The CWA prohibits any discharge into waters of the United States except in compliance with permits issued by federal and state governmental agencies. Failure to comply with the CWA, including discharge limits set by permits issued pursuant to the CWA, may also result in administrative, civil or criminal enforcement actions. The OPA and CWA also require the preparation of oil spill response plans and spill prevention, control and countermeasure or “SPCC” plans. We have such plans in place and have made changes as necessary due to changes by the U.S. Environmental Protection Agency, also known as the “EPA,” and delays in EPA rulemaking. The final EPA rule was published in November 2009 and became effective on January 14, 2010, with a compliance deadline of November 2010.
 
OCSLA authorizes regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Shelf. Specific design and operational standards may apply to vessels, rigs, platforms, vehicles and structures operating or located on the Shelf. Violations of lease conditions or regulations issued pursuant to OCSLA can result in substantial administrative, civil and criminal penalties, as well as potential court injunctions curtailing operations and the cancellation of leases.
 
The Resource Conservation and Recovery Act, or RCRA, generally regulates the disposal of solid and hazardous wastes and imposes certain environmental cleanup obligations. Although RCRA specifically excludes from the definition of hazardous waste “drilling fluids, produced waters and other wastes associated with the exploration, development or production of crude oil, natural gas or geothermal energy,” the EPA and state agencies may regulate these wastes as solid wastes. Moreover, ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste oils, may be regulated as hazardous waste.
 
The Comprehensive Environmental Response, Compensation, and Liability Act, also known as CERCLA or the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on persons that are considered to have contributed to the release of a “hazardous substance” into the environment. Such “responsible persons” may be subject to joint and several liability under the Superfund law for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We currently own or lease onshore properties that have been used for the exploration and production of oil and gas for a number of years. Many of these onshore properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or other wastes was not under our control. These properties and any wastes that may have been disposed or released on them may be subject to the Superfund law, RCRA and analogous state laws and common law obligations, and we potentially could be required to investigate and remediate such properties, including soil or groundwater contamination by prior owners or operators, or to perform remedial plugging or pit closure operations to prevent future contamination.


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The Clean Air Act and comparable state statutes restrict the emission of air pollutants and affects both onshore and offshore oil and gas operations. New facilities may be required to obtain separate construction and operating permits before construction work can begin or operations may start, and existing facilities may be required to incur capital costs in order to remain in compliance. Also, the EPA has developed and continues to develop more stringent regulations governing emissions of toxic air pollutants, and is considering the regulation of additional air pollutants and air pollutant parameters. These regulations may increase the costs of compliance for some facilities.
 
The Safe Drinking Water Act and comparable state statutes restrict the disposal, treatment or release of water produced or used during oil and gas development. Subsurface emplacement of fluids (including disposal wells or enhanced oil recovery) is governed by federal or state regulatory authorities that, in some cases, includes the state oil and gas regulatory authority or the state’s environmental authority. These regulations may increase the costs of compliance for some facilities.
 
The National Environmental Policy Act (NEPA) requires federal agencies to consider potential environmental impacts that may result from projects they approve. The process involves the preparation of either an environmental assessment or environmental impact statement depending on whether the specific circumstances surrounding the proposed federal action will have a significant impact on the human environment. The NEPA process involves public input through comments which can alter the nature of a proposed project either by limiting the scope of the project or requiring resource-specific mitigation. NEPA decisions can be appealed through the court system by process participants. These regulations may increase the costs of compliance for some facilities.
 
The Occupational Safety and Health Act (OSHA) and comparable state statutes regulate the protection of the health and safety of workers. The OSHA hazard communication standard requires maintenance of information about hazardous materials used or produced in operations and provision of such information to employees. Other OSHA standards regulate specific worker safety aspects of our operations. Failure to comply with OSHA requirements can lead to the imposition of penalties.
 
Congress has been actively considering legislation to reduce emissions of greenhouse gases, primarily through the development of greenhouse gas cap and trade programs. In June of 2009, the U.S. House of Representatives passed a cap and trade bill known as the American Clean Energy and Security Act of 2009 although it was never passed by the U.S. Senate. In addition, more than one-third of the states already have begun implementing legal measures to reduce emissions of greenhouse gases. Further, on April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. EPA, held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On April 24, 2009, EPA responded to the Massachusetts, et al. v. EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. EPA published the final version of this finding on December 15, 2009, which allowed EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, EPA proposed a rule in September of 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In response to this issue, EPA also proposed a tailoring rule that would, in general, only impose greenhouse gas permitting requirements on facilities that emit more than 25,000 tons per year of greenhouse gases. Moreover, on September 22, 2009, EPA finalized a rule requiring nation-wide reporting of greenhouse gas emissions in 2011 for emissions occurring in 2010. The rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent greenhouse gas emissions per year, and to most upstream suppliers of fossil fuels and industrial greenhouse gas, as well as to manufacturers of vehicles and engines. Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted to address greenhouse gas emissions would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Any


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additional costs or operating restrictions associated with legislation or regulations regarding greenhouse gas emissions could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.
 
International Regulations.  Our exploration and production operations outside the United States are subject to various types of regulations similar to those described above imposed by the respective governments of the countries in which we operate, and may affect our operations and costs within that country. We currently have operations in Malaysia and China.
 
Commonly Used Oil and Gas Terms
 
Below are explanations of some commonly used terms in the oil and gas business.
 
Barrel or Bbl.  One stock tank barrel, or 42 U.S. gallons liquid volume.
 
Basis risk.  The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular hedging transaction.
 
Bcf.  Billion cubic feet.
 
Bcfe.  Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
BLM.  The Bureau of Land Management of the United States Department of the Interior.
 
BOE.  One barrel of oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
BOEMRE.  Bureau of Ocean Energy Management, Regulation and Enforcement of the U.S. Department of the Interior, formally known as the Minerals Management Service (MMS).
 
BOEPD.  Barrels of oil equivalent per day.
 
BOPD.  Barrels of oil per day.
 
Btu.  British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.
 
Completion.  The installation of permanent equipment for the production of oil or natural gas.
 
Deepwater.  Generally considered to be water depths in excess of 1,000 feet.
 
Developed acreage.  The number of acres that are allocated or assignable to producing wells or wells capable of production.
 
Development well.  A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Exploitation well.  An exploration well drilled to find and produce probable reserves. Most of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte field. Exploitation wells in those areas have less risk and less reserve potential and typically may be drilled at a lower cost than other exploration wells. For internal reporting and budgeting purposes, we combine exploitation and development activities.
 
Exploration well.  An exploration well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well, or a stratigraphic test well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.
 
FERC.  The Federal Energy Regulatory Commission.
 
FPSO.  A floating production, storage and off-loading vessel commonly used overseas to produce oil from locations where pipeline infrastructure is not available.


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Field.  An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.
 
Gross acres or gross wells.  The total acres or wells in which we own a working interest.
 
Infill drilling or infill well.  A well drilled between known producing wells to improve oil and gas reserve recovery efficiency.
 
MBbls.  One thousand barrels of crude oil or other liquid hydrocarbons.
 
MBOE.  One thousand barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
Mcf.  One thousand cubic feet.
 
Mcfe.  One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
MMBbls.  One million barrels of crude oil or other liquid hydrocarbons.
 
MMBOE.  One million barrels of crude oil equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
MMBtu.  One million Btus.
 
MMcfe/d.  One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate, produced per day.
 
MMMBtu.  One billion Btus.
 
Net acres or net wells.  The sum of the fractional working interests we own in gross acres or gross wells, as the case may be.
 
NYMEX.  The New York Mercantile Exchange.
 
NYMEX Henry Hub.  Henry Hub is the major exchange for pricing natural gas futures on the New York Mercantile Exchange. It is frequently referred to as the Henry Hub Index.
 
Probable reserves.  Probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probable reserves in Rule 4-10(a)(18) of Regulation S-X.
 
Productive well.  A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.
 
Proved developed reserves.  In general, proved reserves that can be expected to be recovered from existing wells with existing equipment and operating methods. The SEC provides a complete definition of developed oil and gas reserves in Rule 4-10(a)(6) of Regulation S-X.
 
Proved reserves.  Proved reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible — from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
 
Proved undeveloped reserves.  In general, proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for recompletion. The SEC provides a complete definition of undeveloped oil and gas reserves in Rule 4-10(a)(31) of Regulation S-X.


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Reserve life index.  This index is calculated by dividing total proved reserves at year end by annual production to estimate the number of years of remaining production.
 
Shelf.  The U.S. Outer Continental Shelf of the Gulf of Mexico. Water depths generally range from 50 feet to 1,000 feet.
 
Tcfe.  One trillion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate.
 
Unconventional “resource” plays.  Plays targeting tight sand, coal bed or gas shale reservoirs. The reservoirs tend to cover large areas and lack the readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These reservoirs generally require stimulation treatments or other special recovery processes in order to produce economically.
 
Undeveloped acreage.  Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas regardless of whether such acreage contains proved reserves.
 
Working interest.  The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.
 
Item 1A.   Risk Factors
 
There are many factors that may affect Newfield’s business and results of operations. You should carefully consider, in addition to the other information contained in this report, the risks described below.
 
Oil and gas prices fluctuate widely, and lower prices for an extended period of time are likely to have a material adverse impact on our business.  Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas. Lower prices may reduce the amount of oil and gas that we can economically produce. Oil and gas prices also affect the amount of cash flow available for capital expenditures and our ability to borrow and raise additional capital.
 
Among the factors that can cause fluctuations in oil and gas prices are:
 
  •  the domestic and foreign supply of oil, natural gas and natural gas liquids;
 
  •  the price and availability of, and demand for, alternative fuels;
 
  •  weather conditions and climate change;
 
  •  changes in supply and demand;
 
  •  world-wide economic conditions;
 
  •  the price of foreign imports;
 
  •  the availability, proximity and capacity of transportation facilities and processing facilities;
 
  •  the level and effect of trading in commodity futures markets, including commodity price speculators and others;
 
  •  political conditions in oil and gas producing regions; and
 
  •  the nature and extent of domestic and foreign governmental regulations and taxation, including environmental regulation.


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We have substantial capital requirements to fund our business plans, and a continued slow recovery of the economy and the financial markets in 2011 or another decline or crisis as was experienced in late 2008 and 2009 could negatively impact our ability to execute our business plan.  Although we anticipate that our 2011 capital spending, excluding acquisitions, will correspond with our anticipated 2011 cash flows, we may borrow and repay funds under our credit arrangements throughout the year since the timing of expenditures and the receipt of cash flows from operations do not necessarily match. Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We may have to reduce capital expenditures, and our ability to execute our business plans could be adversely affected, if (1) one or more of the lenders under our existing credit arrangements fail to honor its contractual obligation to lend to us; (2) the amount that we are allowed to borrow under our existing credit facility is reduced as a result of lower oil and gas prices, declines in reserves, lending requirements or for other reasons; or (3) our customers or working interest owners default on their obligations to us.
 
To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new reserves.  Through our drilling programs and the acquisition of properties, we strive to maintain and grow our production and cash flow. However, as we produce from our properties, our reserves decline. We may be unable to find, develop or acquire additional reserves or production at an acceptable cost, if at all. In addition, these activities require substantial capital expenditures.
 
Actual quantities of oil and gas reserves and future cash flows from those reserves will most likely vary from our estimates.  Estimating accumulations of oil and gas is complex. The process relies on interpretations of available geologic, geophysic, engineering and production data. The extent, quality and reliability of this data can vary. The process also requires a number of economic assumptions, such as oil and gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of:
 
  •  the quality and quantity of available data;
 
  •  the interpretation of that data;
 
  •  the accuracy of various mandated economic assumptions; and
 
  •  the judgment of the persons preparing the estimate.
 
The proved and probable reserve information set forth in this report is based on estimates we prepared. Estimates prepared by others might differ materially from our estimates.
 
Actual quantities of oil and gas reserves, future production, oil and gas prices, revenues, taxes, development expenditures and operating expenses will most likely vary from our estimates, with the variability likely to be higher for probable reserves estimates. In addition, the methodologies and evaluation techniques that we use, which include the use of multiple technologies, data sources and interpretation methods, may be different than those used by our competitors. Further, reserve estimates are subject to the evaluator’s criteria and judgment and show important variability, particularly in the early stages of an oil and gas development. Any significant variance could materially affect the quantities and net present value of our reserves. In addition, we may adjust estimates of reserves to reflect production history, results of exploration and development activities and prevailing oil and gas prices. Our reserves also may be susceptible to drainage by operators on adjacent properties.
 
You should not assume that the present value of future net cash flows is the current market value of our proved oil and gas reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flows from proved reserves on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, and costs in effect at year-end. Actual future prices and costs may be materially higher or lower than the prices and costs we used. In addition, actual production rates for future periods may vary significantly from the rates assumed in the calculation.


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Our use of oil and gas price hedging contracts may limit future revenues from price increases and involves the risk that our counterparties may be unable to satisfy their obligations to us.  We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12-24 months as part of our risk management program. In the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. Reducing our exposure to price volatility is intended to help ensure that we have adequate funds available for our capital programs and to help us manage returns on some of our acquisitions and more price sensitive drilling programs. Although the use of hedging transactions limits the downside risk of price declines, it also may limit the benefit from price increases and expose us to the risk of financial loss in certain circumstances. Those circumstances include instances where our production is less than the hedged volume or there is a widening of price basis differentials between delivery points for our production and the delivery points assumed in the hedge transaction.
 
Hedging transactions also involve the risk that counterparties, which generally are financial institutions, may be unable to satisfy their obligations to us. Although we have entered into hedging contracts with multiple counterparties to mitigate our exposure to any individual counterparty, if any of our counterparties were to default on its obligations to us under the hedging contracts or seek bankruptcy protection, it could have a material adverse effect on our ability to fund our planned activities and could result in a larger percentage of our future production being subject to commodity price changes. In addition, in poor economic environments and tight financial markets, the risk of a counterparty default is heightened, and it is possible that fewer counterparties will participate in future hedging transactions, which could result in greater concentration of our exposure to any one counterparty or a larger percentage of our future production being subject to commodity price changes.
 
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 SEC 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 margins in connection with hedging activities. While several senators have indicated that it was not the intent of the Act to require margins 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 oil and gas commodity prices. Any of the foregoing consequences would cause us to reconsider our hedging activities and may limit our ability to mitigate any fluctuations in oil and gas prices, which could have a material adverse effect on our consolidated financial position, results of operations and cash flows.
 
There is limited transportation and refining capacity for our black wax crude oil, which may limit our ability to sell our current production or to increase our production at Monument Butte in the Uinta Basin.  Most of the crude oil we produce in the Uinta Basin is known as “black wax” because it has higher paraffin content than crude oil found in most other major North American basins. Due to its wax content, it must remain heated during shipping, so our transportation options are limited. Currently, the oil is transported by truck to refiners in the Salt Lake City area. We currently have agreements in place with area refiners that secure base load sales of substantially all of our expected production in the Uinta Basin through the end of 2011. In the current economic environment, there is a risk that they may fail to satisfy their obligations to us under those contracts. During the fourth quarter of 2008, the largest purchaser of our black wax crude oil failed to pay for certain deliveries of crude oil and filed for bankruptcy protection. Although we continue to sell our black wax crude oil to that purchaser on a short-term basis that provides for more timely cash


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payments, we cannot guarantee that we will be able to continue to sell to this purchaser or that similar substitute arrangements could be made for sales of our black wax crude oil with other purchasers if desired. An extended loss of any of our largest purchasers could have a material adverse effect on us because there are limited purchasers of our black wax crude. We continue to work with refiners to expand the market for our existing black wax crude oil production and to secure additional capacity to allow for production growth. However, without additional refining capacity, our ability to increase production from the field may be limited.
 
Drilling is a high-risk activity.  In addition to the numerous operating risks described in more detail below, the drilling of wells involves the risk that no commercially productive oil or gas reservoirs will be encountered. In addition, we often are uncertain as to the future cost or timing of drilling, completing and producing wells. Furthermore, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
 
  •  costs of, or shortages or delays in the availability of, drilling rigs, equipment and materials;
 
  •  adverse weather conditions and changes in weather patterns;
 
  •  unexpected drilling conditions;
 
  •  pressure or irregularities in formations;
 
  •  embedded oilfield drilling and service tools;
 
  •  equipment failures or accidents;
 
  •  lack of necessary services or qualified personnel;
 
  •  availability and timely issuance of required governmental permits and licenses;
 
  •  availability, costs and terms of contractual arrangements, such as leases, pipelines and related facilities to gather, process and compress, transport and market natural gas, crude oil and related commodities; and
 
  •  compliance with, or changes in, environmental, tax and other laws and regulations.
 
We are subject to complex laws that can affect the cost, manner or feasibility of doing business.  In addition, potential regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business. Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulation. We may be required to make large expenditures to comply with environmental and other governmental regulations. Matters subject to regulation include:
 
  •  the amounts and types of substances and materials that may be released into the environment;
 
  •  response to unexpected releases to the environment;
 
  •  reports and permits concerning exploration, drilling, production and other operations;
 
  •  the spacing of wells;
 
  •  unitization and pooling of properties;
 
  •  calculating royalties on oil and gas produced under federal and state leases; and
 
  •  taxation.
 
Under these laws, we could be liable for personal injuries, property damage, oil spills, discharge of hazardous materials, remediation and clean-up costs, natural resource damages and other environmental damages. We also could be required to install expensive pollution control measures or limit or cease activities on lands located within wilderness, wetlands or other environmentally or politically sensitive areas. Failure to comply with these laws also may result in the suspension or termination of our operations and subject us to administrative, civil and criminal penalties as well as the imposition of corrective action orders. Any such


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liabilities, penalties, suspensions, terminations or regulatory changes could have a material adverse effect on our financial condition, results of operations or cash flows.
 
In addition, changes to existing regulations or the adoption of new regulations may unfavorably impact us, our suppliers or our customers. For example, governments around the world have become increasingly focused on climate change matters. On April 2, 2007, the United States Supreme Court in Massachusetts, et al. v. the U.S. Environmental Protection Agency (EPA), held that carbon dioxide may be regulated as an “air pollutant” under the federal Clean Air Act. On April 24, 2009, the EPA responded to the Massachusetts, et al. v. the EPA decision with a proposed finding that the current and projected concentrations of greenhouse gases in the atmosphere threaten the public health and welfare of current and future generations, and that certain greenhouse gases from new motor vehicles and motor vehicle engines contribute to the atmospheric concentrations of greenhouse gases and hence to the threat of climate change. The EPA published the final version of this finding on December 15, 2009, which allowed the EPA to proceed with the rulemaking process to regulate greenhouse gases under the Clean Air Act. In anticipation of the finalization of the EPA’s finding that greenhouse gases threaten public health and welfare, and that greenhouse gases from new motor vehicles contribute to climate change, the EPA proposed a rule in September 2009 that would require a reduction in emissions of greenhouse gases from motor vehicles and would trigger applicability of Clean Air Act permitting requirements for certain stationary sources of greenhouse gas emissions. In 2010, the EPA promulgated regulations requiring certain facility owners, as that term is defined under 40 C.F.R. Part 98, to report on greenhouse gas (GHG) emissions from facilities subject to said regulations, which includes, in some situations, facilities involved in the production of oil and natural gas. The initial reporting required under these regulations is forthcoming and will ultimately add regulatory burdens for reporting emissions on certain industries. Generally speaking, the rule applies primarily to large facilities emitting 25,000 metric tons or more of carbon dioxide-equivalent GHG emissions per year, and to most upstream suppliers of fossil fuels and industrial GHG, as well as to manufacturers of vehicles and engines. The new regulations could impact certain facilities in which we have interests (legal, equitable, operated or non-operated) by increasing the regulatory reporting requirements.
 
Other proposed policy changes from regulatory agencies could also increase regulatory reporting requirements, such as hydraulic fracturing regulation on public lands proposed by the U.S. Department of the Interior. In addition, the U.S. Congress in the past has proposed legislation that directly impacts our industry, also covering areas such as emission reporting and reductions, the repeal of certain oil and gas tax incentives and tax deductions, and the regulation of over-the-counter commodity hedging activities. Similarly, in response to the 2010 Macondo incident in the Gulf of Mexico, the U.S. Congress was considering a number of legislative proposals relating to the upstream oil and gas industry both onshore and offshore that could result in significant additional laws or regulations governing our operations in the United States, including a proposal to raise or eliminate the cap on liability for oil spill cleanups under the Oil Pollution Act of 1990.
 
In January 2011, the 112th Session of Congress convened and at the time this report was prepared, no legislation was actively being considered on the topics mentioned herein; however, it is possible that similar legislation as introduced in previous sessions of Congress will be introduced. These and other potential regulations, if introduced and passed in Congress, could increase our costs, reduce our liquidity, delay our operations or otherwise alter the way we conduct our business, negatively impacting our financial condition, results of operations and cash flows.
 
Although it is not possible at this time to predict whether proposed legislation or regulations will be adopted as initially written, if at all, or how legislation or new regulation that may be adopted would impact our business, any such future laws and regulations could result in increased compliance costs or additional operating restrictions. Additional costs or operating restrictions associated with legislation or regulations could have a material adverse effect on our operating results and cash flows, in addition to the demand for the natural gas and other hydrocarbon products that we produce.
 
The potential adoption of federal and state legislative and regulatory initiatives related to hydraulic fracturing could result in operating restrictions or delays in the completion of oil and gas wells.  Hydraulic fracturing is a commonly used process that involves using water, sand, and certain chemicals to fracture the


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hydrocarbon-bearing rock formation to allow flow of hydrocarbons into the wellbore. The U.S. Congress has considered legislation that would require additional regulation affecting the hydraulic fracturing process. Consideration for new federal regulation and increased state oversight continues to arise. To determine if these chemicals could adversely affect drinking water supplies, the EPA announced in the first quarter of 2010 its intention to conduct a comprehensive research study on the potential adverse effects that hydraulic fracturing may have on water quality and public health. The EPA has begun preparation for the study and expects to complete the study in 2012. In addition, various state-level initiatives in regions with substantial shale gas supplies may be proposed or implemented to regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. Moreover, public debate over hydraulic fracturing and shale gas production has been increasing, and has resulted in delays of well permits in some areas.
 
Increased regulation and attention given to the hydraulic fracturing process could lead to greater opposition, including litigation, to oil and gas production activities using hydraulic fracturing techniques. Additional legislation or regulation could also lead to operational delays or increased operating costs in the production of oil and natural gas, including from the developing shale plays, or could make it more difficult to perform hydraulic fracturing. The adoption of any federal or state laws or the implementation of regulations regarding hydraulic fracturing could potentially cause a decrease in the completion of new oil and gas wells and increased compliance costs, which could adversely affect our financial position, results of operations and cash flows.
 
Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and may in the future result in additional ceiling test writedowns or other impairments.  We capitalize the costs to acquire, find and develop our oil and gas properties under the full cost accounting method. The net capitalized costs of our oil and gas properties may not exceed the present value of estimated future net cash flows from proved reserves. If net capitalized costs of our oil and gas properties exceed this limit, we must charge the amount of the excess to earnings. This is called a “ceiling test writedown.” As of December 31, 2008, we recorded a $1.8 billion ($1.1 billion after-tax) ceiling test writedown. We recorded an additional $1.3 billion ($854 million after-tax) ceiling test writedown as of March 31, 2009. Although a ceiling test writedown does not impact cash flows from operations, it does reduce our stockholders’ equity. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase.
 
The risk that we will be required to further write down the carrying value of our oil and gas properties increases when oil and gas prices are low or volatile. In addition, writedowns may occur if we experience substantial downward adjustments to our estimated proved reserves or our unproved property values, or if estimated future development costs increase. We may experience further ceiling test writedowns or other impairments in the future. In addition, any future ceiling test cushion would be subject to fluctuation as a result of acquisition or divestiture activity.
 
The oil and gas business involves many operating risks that can cause substantial losses, and insurance may not protect us against all of these risks.  We are not insured against all risks. Our oil and gas exploration and production activities are subject to all of the operating risks associated with drilling for and producing oil and gas, including the risk of:
 
  •  fires and explosions;
 
  •  blow-outs;
 
  •  uncontrollable or unknown flows of oil, gas, formation water or drilling fluids;
 
  •  adverse weather conditions or natural disasters;
 
  •  pipe or cement failures and casing collapses;
 
  •  pipeline ruptures;
 
  •  discharges of toxic gases;


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  •  build up of naturally occurring radioactive materials; and
 
  •  vandalism.
 
If any of these events occur, we could incur substantial losses as a result of:
 
  •  injury or loss of life;
 
  •  severe damage or destruction of property and equipment, and oil and gas reservoirs;
 
  •  pollution and other environmental damage;
 
  •  investigatory and clean-up responsibilities;
 
  •  regulatory investigation and penalties;
 
  •  suspension of our operations; and
 
  •  repairs to resume operations.
 
If we experience any of these problems, our ability to conduct operations could be adversely affected.
 
Offshore and deepwater operations are subject to a variety of additional operating risks, such as capsizing, collisions and damage or loss from hurricanes or other adverse weather conditions. These conditions have in the past, and may in the future, cause substantial damage to facilities and interrupt production. Some of our offshore operations, and most of our deepwater and international operations, are dependent upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities that we do not own. Necessary infrastructures have been in the past, and may be in the future, temporarily unavailable due to adverse weather conditions or other reasons or may not be available to us in the future at all or on acceptable terms.
 
We maintain insurance against some, but not all, of these potential risks and losses. We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not insurable.
 
The marketability of our production is dependent upon transportation and processing facilities over which we may have no control.  The marketability of our production depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver oil and gas through gathering systems and pipelines that we do not own. The lack of availability of capacity on these systems and facilities could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Although we have some contractual control over the transportation of our production through some firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, or may not be available to us in the future at a price that is acceptable to us. Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could harm our business and, in turn, our financial condition, results of operations and cash flows.
 
Exploration in deepwater involves significant financial risks, and we may be unable to obtain the drilling rigs or support services necessary for our deepwater drilling and development programs in a timely manner or at acceptable rates.  Much of the deepwater play lacks the physical and oilfield service infrastructure necessary for production. As a result, development of a deepwater discovery may be a lengthy process and requires substantial capital investment, and it is difficult to estimate the timing of our production. Because of the size of significant projects in which we invest, we may not serve as the operator. As a result, we may have limited ability to exercise influence over operations related to these projects or their associated costs. Our dependence on the operator and other working interest owners for these deepwater projects and our limited ability to influence operations and associated costs could prevent the realization of our targeted returns on capital or lead to unexpected future losses.


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We have risks associated with our non-U.S. operations.  Ownership of property interests and production operations in areas outside the United States is subject to the various risks inherent in international operations. These risks may include:
 
  •  currency restrictions and exchange rate fluctuations;
 
  •  loss of revenue, property and equipment as a result of expropriation, nationalization, war or insurrection;
 
  •  increases in taxes and governmental royalties;
 
  •  forced renegotiation of, or unilateral changes to, or termination of contracts with governmental entities and quasi-governmental agencies;
 
  •  changes in laws and policies governing operations of non-U.S. based companies;
 
  •  our limited ability to influence or control the operation or future development of these non-operated properties;
 
  •  the operator’s expertise or other labor problems;
 
  •  difficulties enforcing our rights against a governmental entity because of the doctrine of sovereign immunity and foreign sovereignty over international operations; and
 
  •  other uncertainties arising out of foreign government sovereignty over our international operations.
 
Our international operations also may be adversely affected by the laws and policies of the United States affecting foreign trade, taxation and investment. In addition, if a dispute arises with respect to our international operations, we may be subject to the exclusive jurisdiction of non-U.S. courts or may not be successful in subjecting non-U.S. persons to the jurisdiction of the courts of the United States.
 
We may be subject to risks in connection with acquisitions.  The successful acquisition of producing properties requires an assessment of several factors, including:
 
  •  recoverable reserves;
 
  •  future oil and gas prices and their appropriate differentials;
 
  •  operating costs; and
 
  •  potential environmental and other liabilities.
 
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections will not likely be performed on every well or facility, and structural and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.
 
Competition for experienced technical personnel may negatively impact our operations or financial results.  Our continued drilling success and the success of other activities integral to our operations will depend, in part, on our ability to attract and retain experienced explorationists, engineers and other professionals. Competition for these professionals remains strong. We are likely to continue to experience increased costs to attract and retain these professionals.
 
There is competition for available oil and gas properties.  Our competitors include major oil and gas companies, independent oil and gas companies and financial buyers. Some of our competitors may have greater and more diverse resources than we do. High commodity prices and stiff competition for acquisitions have in the past, and may in the future, significantly increase the cost of available properties.


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Our certificate of incorporation, bylaws, some of our arrangements with employees and Delaware law contain provisions that could discourage an acquisition or change of control of our company.  Our certificate of incorporation and bylaws contain provisions that may make it more difficult to effect a change of control of our company, to acquire us or to replace incumbent management. In addition, our change of control severance plan and agreements, our omnibus stock plans and our incentive compensation plan contain provisions that provide for severance payments and accelerated vesting of benefits, including accelerated vesting of restricted stock, restricted stock units and stock options, upon a change of control. Section 203 of the Delaware General Corporation Law also imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions could discourage or prevent a change of control or reduce the price our stockholders receive in an acquisition of our company.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
Item 3.   Legal Proceedings
 
In August 2010, we received a Notice of Violation (NOV) from the U.S. Environmental Protection Agency (the EPA) alleging that we failed to provide adequate financial assurance for some of the water injection wells falling under EPA jurisdiction that are located at our Monument Butte field in Duchesne County, Utah (Monument Butte). The injection wells are part of an enhanced oil recovery project designed to optimize production from Monument Butte. Regulations under the Safe Drinking Water Act, or SDWA, require operators of injection wells to file proof of financial assurance annually to cover the costs to plug and abandon the injection wells. The NOV alleges that our 2010 filing (for 2009) did not meet the financial ratio tests required under SDWA regulations. Upon receipt of the NOV, we promptly complied with the EPA’s request to put in place additional alternate financial assurance for the wells. We have held preliminary discussions with the EPA regarding potential settlement of this matter; however, the amount of penalty to be paid has not been ascertained and a schedule for resolving this matter with the EPA has not been established. The NOV was administrative in nature and did not contain any allegations of environmental spills, releases or pollution. Although the outcome of this matter cannot be predicted with certainty, we do not expect it to have a material adverse effect on our financial position, cash flows or results of operations.
 
In addition to the foregoing matter, we have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (1) claims from royalty owners for disputed royalty payments, (2) commercial disputes, (3) personal injury claims and (4) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of our security holders during the fourth quarter of 2010.


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The following table sets forth the names of, ages (as of February 15, 2011) of and positions held by our executive officers. Our executive officers serve at the discretion of our Board of Directors.
                     
            Total Years
            of Service
            with
Name
  Age  
Position
  Newfield
 
Lee K. Boothby
    49     President, Chief Executive Officer and Chairman of the Board     11  
Gary D. Packer
    48     Executive Vice President and Chief Operating Officer     15  
Terry W. Rathert
    58     Executive Vice President and Chief Financial Officer     21  
George T. Dunn
    53     Vice President — Mid-Continent     18  
Daryll T. Howard
    48     Vice President — Rocky Mountains     14  
John H. Jasek
    41     Vice President — Onshore Gulf Coast     11  
William D. Schneider
    59     Vice President — Gulf of Mexico and International     22  
John D. Marziotti
    47     General Counsel and Secretary     7  
Brian L. Rickmers
    42     Controller and Assistant Secretary     17  
 
The executive officers have held the positions indicated above for the past five years, except as follows:
 
Lee K. Boothby was promoted to the position of President on February 5, 2009 and to the additional role of Chief Executive Officer on May 7, 2009. Our Board of Directors also has named Mr. Boothby to the additional role of Chairman of the Board, effective May 7, 2010. Prior to February 5, 2009, Mr. Boothby served as Senior Vice President — Acquisitions & Business Development since October 2007. He managed our Mid-Continent operations from February 2002 to October 2007, and was promoted from General Manager to Vice President in November 2004.
 
Gary D. Packer was promoted to the position of Executive Vice President and Chief Operating Officer on May 7, 2009. Prior thereto, he was promoted from Gulf of Mexico General Manager to Vice President — Rocky Mountains in November 2004.
 
Terry W. Rathert was promoted from Senior Vice President to Executive Vice President on May 7, 2009 and previously was promoted from Vice President to Senior Vice President in November 2004. He also served as Secretary of our company until May 2008.
 
George T. Dunn was named Vice President — Mid-Continent in October 2007. He managed our onshore Gulf Coast operations from 2001 to October 2007, and was promoted from General Manager to Vice President in November 2004.
 
Daryll T. Howard was promoted to the position of Vice President — Rocky Mountains on May 7, 2009. Mr. Howard joined Newfield in 1996. Prior to his promotion on May 7, 2009, Mr. Howard served as East Team Rocky Mountain Asset Manager since June 2008. Prior thereto, Mr. Howard assisted in establishing Newfield’s Malaysia office and was instrumental in the success and growth of Newfield’s international operations. Mr. Howard also previously held several positions of increasing breadth and responsibility in Newfield’s Gulf of Mexico organization.
 
John H. Jasek was reappointed as Vice President — Onshore Gulf Coast on February 15, 2011. Prior to that, he was reappointed as Vice President — Gulf of Mexico in December 2008. Mr. Jasek served as Vice President — Gulf Coast from October 2007 until December 2008 while also serving as the manager of our onshore Gulf Coast operations. He previously managed our Gulf of Mexico operations from March 2005 until October 2007, and was promoted from General Manager to Vice President in November 2006. Prior to March 2005, he was a Petroleum Engineer in the Western Gulf of Mexico.
 
William D. Schneider was appointed Vice President — Gulf of Mexico and International on February 15, 2011. Prior to that, he served as Vice President — Onshore Gulf Coast and International from December 2008 until February 2011. He has managed our international operations since May 2000.
 
John D. Marziotti was promoted to General Counsel in August 2007 and was named Secretary in May 2008. From November 2003, when he joined our company, until August 2007 he held the position of Legal Counsel. Prior to joining us, he was a shareholder of the law firm of Strasburger & Price, LLP.


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PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Market for Common Stock
 
Our common stock is listed on the New York Stock Exchange under the symbol “NFX.” The following table sets forth, for each of the periods indicated, the high and low reported sales price of our common stock on the NYSE.
 
                 
    High   Low
 
2009:
               
First Quarter
  $ 26.50     $ 17.09  
Second Quarter
    38.74       21.65  
Third Quarter
    46.62       27.92  
Fourth Quarter
    51.27       39.26  
2010:
               
First Quarter
  $ 55.20     $ 47.21  
Second Quarter
    60.50       44.81  
Third Quarter
    57.99       46.11  
Fourth Quarter
    73.58       56.70  
2011:
               
First Quarter (through February 22, 2011)
  $ 76.55     $ 65.72  
 
On February 22, 2011, the last reported sales price of our common stock on the NYSE was $65.98. As of that date, there were approximately 1,811 holders of record of our common stock.
 
Dividends
 
We have not paid any cash dividends on our common stock and do not intend to do so in the foreseeable future. We intend to retain earnings for the future operation and development of our business. Any future cash dividends to holders of our common stock would depend on future earnings, capital requirements, our financial condition and other factors determined by our Board of Directors. The covenants contained in our credit facility and in the indentures governing our 65/8% Senior Subordinated Notes due 2014 and 2016, our 71/8% Senior Subordinated Notes due 2018 and our 67/8% Senior Subordinated Notes due 2020 could restrict our ability to pay cash dividends. See “Contractual Obligations” under Item 7 of this report and Note 8, “Debt,” to our consolidated financial statements under Item 8 of this report.
 
Issuer Purchases of Equity Securities
 
The following table sets forth certain information with respect to repurchases of our common stock during the three months ended December 31, 2010.
 
                                 
                      Maximum Number
 
                Total Number of
    (or Approximate
 
                Shares Purchased
    Dollar Value) of
 
    Total Number of
          as Part of Publicly
    Shares that May Yet
 
    Shares
    Average Price
    Announced Plans
    be Purchased Under
 
Period
  Purchased(1)     Paid per Share     or Programs     the Plans or Programs  
 
October 1 — October 31, 2010
    12,596     $ 58.42              
November 1 — November 30, 2010
    10,332       61.95              
December 1 — December 31, 2010
    2,918       66.24              
                                 
Total
    25,846     $ 60.71              
                                 
 
 
(1) All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards and restricted stock units. These repurchases were not part of a publicly announced program to repurchase shares of our common stock.


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Stockholder Return Performance Presentation
 
The performance presentation shown below is being furnished pursuant to applicable rules of the SEC. As required by these rules, the performance graph was prepared based upon the following assumptions:
 
  •  $100 was invested in our common stock, the S&P 500 Index, and our peer group on December 31, 2005 at the closing price on such date;
 
  •  investment in our peer group was weighted based on the stock market capitalization of each individual company within the peer group at the beginning of the period; and
 
  •  dividends were reinvested on the relevant payment dates.
 
Peer Group.  Our peer group consists of Cabot Oil & Gas Corporation, Cimarex Energy Company, Denbury Resources Inc., EXCO Resources, Inc., Forest Oil Corporation, Noble Energy, Inc., Petrohawk Energy Corporation, Pioneer Natural Resources Company, Plains Exploration & Production Company, Range Resources Corporation, SandRidge Energy, Inc., Southwestern Energy Company and Ultra Petroleum Corp.
 
Comparison of 5 Year Cumulative Total Return
 
(PERFORMANCE GRAPH)
 
 
                                                             
Total Return Analysis     12/31/2005     12/31/2006     12/31/2007     12/31/2008     12/31/2009     12/31/2010
Newfield Exploration Company
    $ 100.00       $ 91.76       $ 105.25       $ 39.44       $ 96.31       $ 144.00  
Peer Group
    $ 100.00       $ 98.71       $ 148.53       $ 84.71       $ 136.76       $ 146.36  
S&P 500
    $ 100.00       $ 115.79       $ 122.16       $ 76.97       $ 97.32       $ 111.98  
                                                             


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Item 6.   Selected Financial Data
 
SELECTED FIVE-YEAR FINANCIAL AND RESERVE DATA
 
The following table shows selected consolidated financial data derived from our consolidated financial statements and selected reserve data derived from our supplementary oil and gas disclosures set forth in Item 8 of this report. The data should be read in conjunction with Items 1 and 2, “Business and Properties — Reserves” and Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” of this report.
 
                                         
    Year Ended December 31,
    2010(1)   2009(1)   2008   2007   2006
        (In millions, except per share data)    
 
Income Statement Data:
                                       
Oil and gas revenues
  $ 1,883     $ 1,338     $ 2,225     $ 1,783     $ 1,673  
Income (loss) from continuing operations
    523       (542 )     (373 )     172       610  
Net income (loss)
    523       (542 )     (373 )     450       591  
Earnings (loss) per share:
                                       
Basic —
                                       
Income (loss) from continuing operations
    3.97       (4.18 )     (2.88 )     1.35       4.82  
Net income (loss)
    3.97       (4.18 )     (2.88 )     3.52       4.67  
Diluted —
                                       
Income (loss) from continuing operations
    3.91       (4.18 )     (2.88 )     1.32       4.73  
Net income (loss)
    3.91       (4.18 )     (2.88 )     3.44       4.58  
Weighted-average number of shares outstanding for basic earnings per share
    132       130       129       128       127  
Weighted-average number of shares outstanding for
                                       
diluted earnings per share
    134       130       129       131       129  
Cash Flow Data:
                                       
Net cash provided by continuing operating activities
  $ 1,630     $ 1,578     $ 854     $ 1,166     $ 1,392  
Net cash used in continuing investing activities
    (1,951 )     (1,356 )     (2,253 )     (865 )     (1,552 )
Net cash provided by (used in) continuing financing
                                       
activities
    282       (168 )     1,173       (117 )     174  
Balance Sheet Data (at end of period):
                                       
Total assets
  $ 7,494     $ 6,254     $ 7,305     $ 6,986     $ 6,635  
Long-term debt
    2,304       2,037       2,213       1,050       1,048  
Proved Reserves Data (at end of period):
                                       
Oil and condensate (MMBbls)
    204       169       140       114       114  
Gas (Bcf)
    2,492       2,605       2,110       1,810       1,586  
Total proved reserves (Bcfe)
    3,712       3,616       2,950       2,496       2,272  
Present value of estimated future after-tax net cash
                                       
flows
  $ 4,754     $ 2,864     $ 2,929     $ 4,531     $ 3,447  
 
 
(1) Effective December 31, 2009, we adopted revised authoritative accounting and disclosure requirements for oil and gas reserves. As a result, 2010 and 2009 disclosures are not on a basis comparable to the prior years. Please see Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations — New Accounting Requirements,” of this report.


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Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
Overview
 
We are an independent oil and gas company engaged in the exploration, development and acquisition of oil and gas properties. Our domestic areas of operation include the Anadarko and Arkoma basins of the Mid-Continent, the Rocky Mountains, onshore Texas, Appalachia and the Gulf of Mexico. Internationally, we are active in Malaysia and China.
 
Our revenues, profitability and future growth depend substantially on prevailing prices for oil and gas and on our ability to find, develop and acquire oil and gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and gas reserves. We use the full cost method of accounting for our oil and gas activities.
 
Oil and Gas Prices.  Prices for oil and gas fluctuate widely. Oil and gas prices affect:
 
  •  the amount of cash flows available for capital expenditures;
 
  •  our ability to borrow and raise additional capital;
 
  •  the quantity of oil and gas that we can economically produce; and
 
  •  the accounting for our oil and gas activities including among other items, the determination of ceiling test writedowns.
 
Any extended decline in oil and gas prices could have a material adverse effect on our financial position, results of operations, cash flows and access to capital. Please see the discussion under “Lower oil and gas prices and other factors have resulted in ceiling test writedowns in the past and may in the future result in additional ceiling test writedowns or other impairments” in Item 1A of this report and “— Liquidity and Capital Resources” below.
 
As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs.
 
Reserve Replacement.  To maintain and grow our production and cash flow, we must continue to develop existing reserves and locate or acquire new oil and gas reserves to replace those reserves being produced. Please see “— Proved Reserves” below and “Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Estimated Net Quantities of Proved Oil and Gas Reserves” in Item 8 of this report for the change in our total net proved reserves during the three-year period ended December 31, 2010. Substantial capital expenditures are required to find, develop and acquire oil and gas reserves. See Items 1 and 2, “Business and Properties — Reserves — Proved Reserves.”
 
Significant Estimates.  We believe the most difficult, subjective or complex judgments and estimates we must make in connection with the preparation of our financial statements are:
 
  •  the quantity of our proved oil and gas reserves;
 
  •  the timing of future drilling, development and abandonment activities;
 
  •  the cost of these activities in the future;
 
  •  the fair value of the assets and liabilities of acquired companies;
 
  •  the fair value of our financial instruments including derivative positions; and
 
  •  the fair value of stock-based compensation.


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Accounting for Hedging Activities.  We do not designate price risk management activities as accounting hedges. Because hedges not designated for hedge accounting are accounted for on a mark-to-market basis, we have in the past experienced, and are likely in the future to experience, significant non-cash volatility in our reported earnings during periods of commodity price volatility. As of December 31, 2010, we had net derivative assets of $137 million, of which 35% was measured based upon our valuation model (i.e. Black-Scholes) and, as such, is classified as a Level 3 fair value measurement. We value these contracts using a model that considers various inputs including (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties. Please see “— Critical Accounting Policies and Estimates — Commodity Derivative Activities” below and Note 4, “Derivative Financial Instruments,” and Note 7, “Fair Value Measurements,” to our consolidated financial statements in Item 8 of this report for a discussion of the accounting applicable to our oil and gas derivative contracts.
 
Results of Operations
 
Revenues.  All of our revenues are derived from the sale of our oil and gas production and do not include the effects of the settlements of our hedges. Please see Note 4, “Derivative Financial Instruments,” to our consolidated financial statements appearing in Item 8 of this report for a discussion of the accounting applicable to our oil and gas derivative contracts.
 
Our revenues may vary significantly from period-to-period as a result of changes in commodity prices or volumes of production sold. In addition, crude oil from our operations offshore Malaysia and China is produced into FPSOs and “lifted” and sold periodically as barge quantities are accumulated. Revenues are recorded when oil is lifted and sold, not when it is produced into the FPSO. As a result, the timing of liftings may impact period-to-period results.


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Revenues of $1.9 billion for 2010 were 41% higher than 2009 revenues primarily due to increased oil and gas production and higher average realized oil and gas prices. Revenues of $1.3 billion for 2009 were 40% lower than 2008 revenues due to significantly lower average realized oil and gas prices partially offset by higher oil and gas production.
 
                         
    Year Ended December 31,
    2010   2009   2008
 
Production(1):
                       
Domestic:
                       
Natural gas (Bcf)
    196.0       174.3       172.9  
Oil and condensate (MBbls)
    8,498       7,059       6,136  
Total (Bcfe)
    247.0       216.7       209.8  
International:
                       
Natural gas (Bcf)
                 
Oil and condensate (MBbls)
    6,057       6,120       4,439  
Total (Bcfe)
    36.3       36.7       26.6  
Total:
                       
Natural gas (Bcf)
    196.0       174.3       172.9  
Oil and condensate (MBbls)
    14,555       13,179       10,575  
Total (Bcfe)
    283.3       253.4       236.4  
Average Realized Prices(2):
                       
Domestic:
                       
Natural gas (per Mcf)
  $ 4.25     $ 3.48     $ 7.65  
Oil and condensate (per Bbl)
    69.03       51.19       86.84  
Natural gas equivalent (per Mcfe)
    5.78       4.47       8.85  
International:
                       
Natural gas (per Mcf)
  $     $     $  
Oil and condensate (per Bbl)
    75.27       59.72       82.03  
Natural gas equivalent (per Mcfe)
    12.54       9.95       13.67  
Total:
                       
Natural gas (per Mcf)
  $ 4.25     $ 3.48     $ 7.65  
Oil and condensate (per Bbl)
    71.62       55.15       84.82  
Natural gas equivalent (per Mcfe)
    6.65       5.28       9.39  
 
 
(1) Represents volumes lifted and sold regardless of when produced. Excludes natural gas produced and consumed in our operations of 5.3 Bcfe in 2010 and 4 Bcfe in both 2009 and 2008.
 
(2) Had we included the effects of hedging contracts not designated for hedge accounting, our average realized price for total natural gas would have been $5.70, $6.42 and $7.12 per Mcf for 2010, 2009 and 2008, respectively. Our total oil and condensate average realized price would have been $81.32, $81.23 and $69.13 per Bbl for 2010, 2009 and 2008, respectively.
 
Domestic Production.  Our 2010 domestic oil and gas production, stated on a natural gas equivalent basis, increased 14% over 2009 production primarily due to increased production from our Mid-Continent and Rocky Mountain divisions as a result of continued successful development drilling efforts, combined with increased production from further development of our Gulf of Mexico deepwater discoveries, partially offset by a decline in our onshore Gulf Coast production.
 
Our 2009 domestic oil and gas production, stated on a natural gas equivalent basis, increased 3% over 2008 production primarily due to increased production in our Mid-Continent division as a result of continued successful drilling efforts, partially offset by natural field declines and the voluntary curtailment of


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approximately 3 Bcfe of production during the second half of 2009 from our Mid-Continent division due to low natural gas prices.
 
International Production.  Our 2010 international oil production, stated on a natural gas equivalent basis, decreased slightly from 2009 levels primarily due to the timing of liftings from our oil production in Malaysia. Our 2009 international oil production, stated on a natural gas equivalent basis, increased 38% over 2008 production primarily due to new field developments on PM 318 and PM 323 in Malaysia and the timing of liftings from our oil production in Malaysia.
 
Operating Expenses.  We believe the most informative way to analyze changes in our operating expenses from period-to-period is on a unit-of-production, or per Mcfe, basis.
 
Year ended December 31, 2010 compared to December 31, 2009
 
The following table presents information about our operating expenses for the two-year period ended December 31, 2010.
 
                                                 
    Unit-of-Production     Total Amount  
    Year Ended
    Percentage
    Year Ended
    Percentage
 
    December 31,     Increase
    December 31,     Increase
 
    2010     2009     (Decrease)     2010     2009     (Decrease)  
    (Per Mcfe)           (In millions)        
 
Domestic:
                                               
Lease operating
  $ 1.07     $ 0.94       14 %   $ 264     $ 203       30 %
Production and other taxes
    0.18       0.15       20 %     44       33       36 %
Depreciation, depletion and amortization
    2.08       2.14       (3 )%     515       463       11 %
General and administrative
    0.61       0.64       (5 )%     150       139       8 %
Ceiling test and other impairments
    0.03       6.20       (100 )%     7       1,344       (99 )%
Other
    0.04       0.03       33 %     10       8       28 %
                                                 
Total operating expenses
    4.01       10.10       (60 )%     990       2,190       (55 )%
International:
                                               
Lease operating
  $ 1.72     $ 1.53       12 %   $ 62     $ 56       11 %
Production and other taxes
    2.25       0.82       174 %     82       30       173 %
Depreciation, depletion and amortization
    3.56       3.39       5 %     129       124       4 %
General and administrative
    0.17       0.14       21 %     6       5       17 %
                                                 
Total operating expenses
    7.70       5.88       31 %     279       215       30 %
Total:
                                               
Lease operating
  $ 1.15     $ 1.02       13 %   $ 326     $ 259       26 %
Production and other taxes
    0.44       0.25       76 %     126       63       102 %
Depreciation, depletion and amortization
    2.27       2.32       (2 )%     644       587       10 %
General and administrative
    0.55       0.57       (4 )%     156       144       8 %
Ceiling test and other impairments
    0.03       5.30       (99 )%     7       1,344       (99 )%
Other
    0.03       0.03             10       8       28 %
                                                 
Total operating expenses
    4.47       9.49       (53 )%     1,269       2,405       (47 )%
 
Domestic Operations.  Our domestic operating expenses for 2010, stated on a Mcfe basis, decreased 60% as compared to 2009 primarily due to the full cost ceiling test writedown recorded at March 31, 2009. The components of the significant period-to-period change are as follows:
 
  •  Lease operating expense (LOE) per Mcfe increased 14% primarily due to increased transportation costs resulting from the commencement of firm transportation contracts during late 2009 and throughout 2010 in our Mid-Continent division.
 
  •  Production and other taxes per Mcfe increased 20% primarily due to higher realized commodity prices during 2010.


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  •  Total DD&A expense for 2010 increased 11% primarily as a result of the 14% increase in our production volumes during 2010 compared to 2009.
 
  •  Total general and administrative (G&A) expense increased 8% primarily due to increased employee-related expenses associated with our growing domestic workforce. Employee-related expenses include incentive compensation expense which is based on our company performance in comparison with peer companies in our industry as defined in the incentive compensation plan in effect during 2010. During 2010, we capitalized $61 million ($0.25 per Mcfe) of direct internal costs as compared to $58 million ($0.27 per Mcfe) in 2009.
 
  •  During the fourth quarter of 2010, we recorded an impairment of $7 million ($0.03 per Mcfe) related to certain claims related to the bankruptcy proceedings associated with TXCO Resources Inc. In 2009, we recorded a ceiling test writedown of $1.3 billion ($6.20 per Mcfe) due to significantly lower natural gas prices at March 31, 2009.
 
  •  Other expenses for 2010 includes the early redemption premium of $12 million associated with the tender offer and repurchase of our $175 million aggregate principal amount of 75/8% Senior Notes due 2011, partially offset by the $2 million cash received resulting from the termination of the associated interest rate swap. Other expenses for 2009 includes long-term rig contract termination fees.
 
International Operations.  Our international operating expenses for 2010, stated on a Mcfe basis, increased 31% over the same period of 2009 primarily as a result of significantly higher production taxes during 2010 due to substantially higher realized oil prices. The components of the significant period-to-period change are as follows:
 
  •  LOE per Mcfe increased 12% primarily due to fixed production and operating costs associated with certain of our production sharing contracts (PSCs) in Malaysia, a change in the mix of produced, lifted and sold production from various PSCs during 2010 compared to the same period of 2009 and increased workover activity.
 
  •  Production and other taxes per Mcfe increased significantly due to an increase, per the terms of the PSCs, in the tax rate per barrel of oil lifted and sold as a result of substantially higher realized oil prices during 2010.


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Year ended December 31, 2009 compared to December 31, 2008
 
The following table presents information about our operating expenses for the two-year period ended December 31, 2009.
 
                                                 
    Unit-of-Production     Total Amount  
    Year Ended
    Percentage
    Year Ended
    Percentage
 
    December 31,     Increase
    December 31,     Increase
 
    2009     2008     (Decrease)     2009     2008     (Decrease)  
    (Per Mcfe)           (In millions)        
 
Domestic:
                                               
Lease operating
  $ 0.94     $ 1.00       (6 )%   $ 203     $ 210       (4 )%
Production and other taxes
    0.15       0.29       (48 )%     33       60       (46 )%
Depreciation, depletion and amortization
    2.14       2.84       (25 )%     463       597       (22 )%
General and administrative
    0.64       0.65       (2 )%     139       136       2 %
Ceiling test and other impairments
    6.20       8.54       (27 )%     1,344       1,792       (25 )%
Other
    0.03       0.02       50 %     8       4       124 %
                                                 
Total operating expenses
    10.10       13.34       (24 )%     2,190       2,799       (22 )%
International:
                                               
Lease operating
  $ 1.53     $ 2.05       (25 )%   $ 56       55       3 %
Production and other taxes
    0.82       3.64       (77 )%     30       97       (69 )%
Depreciation, depletion and amortization
    3.39       3.77       (10 )%     124       100       24 %
General and administrative
    0.14       0.18       (22 )%     5       5       12 %
Ceiling test and other impairments
          2.66       (100 )%           71       (100 )%
                                                 
Total operating expenses
    5.88       12.30       (52 )%     215       328       (34 )%
Total:
                                               
Lease operating
  $ 1.02     $ 1.12       (9 )%   $ 259       265       (2 )%
Production and other taxes
    0.25       0.66       (62 )%     63       157       (60 )%
Depreciation, depletion and amortization
    2.32       2.95       (21 )%     587       697       (16 )%
General and administrative
    0.57       0.60       (5 )%     144       141       2 %
Ceiling test and other impairments
    5.30       7.88       (33 )%     1,344       1,863       (28 )%
Other
    0.03       0.01       200 %     8       4       124 %
                                                 
Total operating expenses
    9.49       13.22       (28 )%     2,405       3,127       (23 )%
 
Domestic Operations.  Our domestic operating expenses for 2009, stated on a Mcfe basis, decreased 24% compared to 2008 primarily due to the goodwill impairment charge recorded at December 31, 2008 and the magnitude of the full cost ceiling test writedowns recorded at December 31, 2008 and March 31, 2009. The components of the period-to-period change are as follows:
 
  •  LOE decreased 6% per Mcfe due to lower overall operating and service costs and the 3% increase in production volumes period-over-period.
 
  •  Production and other taxes decreased 48% per Mcfe due to significantly lower realized commodity prices period-over-period. We received refunds of $24 million ($0.11 per Mcfe) during 2009 related to production tax exemptions on some of our onshore wells, whereas we received similar refunds of $35 million ($0.17 per Mcfe) during 2008.
 
  •  Our DD&A rate decreased 25% per Mcfe primarily as a result of the ceiling test writedowns recorded at December 31, 2008 and March 31, 2009.
 
  •  G&A expense per Mcfe decreased 2% period-over-period while total G&A expense increased slightly. The decrease per Mcfe is primarily due to the 3% increase in production volumes period-over-period. The slight increase in total G&A is primarily due to increased employee-related expenses associated


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  with our growing domestic workforce. Employee-related expenses included incentive compensation expense which decreased approximately 20% period-over-period. Incentive compensation expense was calculated based on adjusted net income as defined in the incentive compensation plan in effect during 2009 and 2008. During 2009, we capitalized $58 million ($0.27 per Mcfe) of direct internal costs as compared to $49 million ($0.23 per Mcfe) in 2008.
 
  •  In 2009, we recorded a ceiling test writedown of $1.3 billion ($6.20 per Mcfe) due to significantly lower natural gas prices at March 31, 2009. In 2008, we recorded a ceiling test writedown of $1.7 billion ($8.25 per Mcfe) due to significantly lower oil and gas commodity prices at year-end 2008. In 2008, we also recorded a goodwill impairment charge of $62 million ($0.29 per Mcfe) due to the significant decline in oil and gas commodity prices and the decline in our market capitalization at that time.
 
  •  Other expenses for 2009 includes long-term rig contract termination fees resulting from our decision to limit our 2009 capital expenditures to a level that we expected to be funded with cash flows from operations. Other expenses for 2008 includes the reversal of a portion of accrued business interruption insurance claims related to 2005 Hurricane Ivan which were determined during 2008 to be uncollectible.
 
International Operations.  Our international operating expenses for 2009, stated on a Mcfe basis, decreased 52% over the same period of 2008 primarily due to the 2008 full cost ceiling test writedown in Malaysia and significantly higher production taxes during 2008 due to substantially higher oil prices. The components of the period-to-period change are as follows:
 
  •  LOE decreased 25% per Mcfe while total LOE increased slightly over 2008. The decrease in LOE per Mcfe is primarily due to increased production volumes associated with the new field developments on PM 318 and PM 323 in Malaysia and lower overall operating and service costs.
 
  •  Production and other taxes decreased significantly due to substantially lower realized oil prices during 2009.
 
  •  Total DD&A expense increased 24% primarily due to additional production volumes and the timing of liftings of these volumes associated with new field developments on PM 318 and PM 323 in Malaysia, partially offset by a decrease in the DD&A rate resulting from the 2008 Malaysia ceiling test writedown.
 
  •  G&A expense decreased 22% per Mcfe primarily due to the 38% increase in production volumes in 2009.
 
  •  In 2008, we recorded a ceiling test writedown of $71 million associated with our operations in Malaysia due to significantly lower oil prices at year-end 2008.
 
Interest Expense.  The following table presents information about interest expense for each of the years in the three-year period ended December 31, 2010:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (In millions)  
 
Gross interest expense:
                       
Credit arrangements
  $ 3     $ 8     $ 10  
Senior notes
    2       12       13  
Senior subordinated notes
    149       102       87  
Other
    2       4       2  
                         
Total gross interest expense
    156       126       112  
Capitalized interest
    (58 )     (51 )     (60 )
                         
Net interest expense
  $ 98     $ 75     $ 52  
                         


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The increase in gross interest expense in 2010 as compared to 2009 primarily resulted from the January 2010 issuance of $700 million aggregate principal amount of 67/8% Senior Subordinated Notes due 2020, partially offset by the tender and repurchase of our $175 million aggregate principal amount of 75/8% Senior Notes during the first half of 2010 and lower outstanding borrowings under our credit arrangements during 2010. The increase in gross interest expense in 2009 as compared to 2008 primarily resulted from the May 2008 issuance of $600 million principal amount of our 71/8% Senior Subordinated Notes due 2018. See Note 8, “Debt,” to our consolidated financial statements appearing later in this report.
 
We capitalize interest with respect to our unproved properties. Capitalized interest during 2010 increased as compared to 2009 due to an increase in our unproved property base primarily as a result of the Maverick Basin asset acquisition in February 2010. Capitalized interest during 2009 decreased as compared to 2008 due to a reduction in our unproved property base resulting from the evaluation of such leasehold acreage.
 
Commodity Derivative Income.  The significant fluctuation in commodity derivative income from period-to-period is due to the extreme volatility of oil and gas prices and changes in our outstanding hedging contracts during these periods.
 
Taxes.  The effective tax rates for the years ended December 31, 2010, 2009, 2008 were 37%, 39%, and 30%, respectively. Our effective tax rate for all periods was different than the federal statutory tax rate due to deductions that do not generate tax benefits, state income taxes and the differences between international and U.S. federal statutory rates. Our effective tax rate generally approximates 37%. Our effective tax rate for 2009 was impacted by the release of the valuation allowance related to the Malaysia tax benefit recorded in 2008. Our effective tax rate for 2008 was lower than the federal statutory tax rate because we were not able to recognize the full tax benefit associated with the $71 million ceiling test writedown in Malaysia and the $62 million goodwill impairment did not generate a tax benefit.
 
Estimates of future taxable income can be significantly affected by changes in oil and gas prices, the timing, amount, and location of future production and future operating expenses and capital costs.
 
Liquidity and Capital Resources
 
We must find new and develop existing reserves to maintain and grow our production and cash flow. We accomplish this through successful drilling programs and the acquisition of properties. These activities require substantial capital expenditures. Lower prices for oil and gas may reduce the amount of oil and gas that we can economically produce, and can also affect the amount of cash flows available for capital expenditures and our ability to borrow and raise additional capital, as further described below.
 
We establish a capital budget at the beginning of each calendar year. Our 2011 capital budget (excluding acquisitions) approximates our estimate of 2011 cash flows from operations. Approximately 70% of our expected 2011 domestic oil and gas production supporting the estimate of cash flows is hedged. Our 2011 capital budget, excluding capitalized interest and overhead of $170 million, is approximately $1.7 billion and focuses on projects we believe will generate and lay the foundation for significant oil production growth in 2011. Accordingly, approximately two-thirds of the 2011 budget will be allocated to oil projects and substantially all the remainder is planned for “liquids rich” gas plays.
 
Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We have the operational flexibility to react quickly with our capital expenditures to changes in circumstances and our cash flows from operations.
 
Credit Arrangements.  We have a revolving credit facility that matures in June 2012 and provides for loan commitments of $1.25 billion from a syndicate of more than 15 financial institutions, led by JPMorgan Chase Bank, as agent. As of December 31, 2010, the largest commitment was 16% of total commitments.


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In the future, total commitments under the facility could be increased to a maximum of $1.65 billion if the existing lenders increase their individual loan commitments or new financial institutions are added to the facility. In addition, subject to compliance with covenants in our credit facility that restrict our ability to incur additional debt, as of December 31, 2010, we also have a total of $105 million of borrowing capacity under money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institution. For a more detailed description of the terms of our credit arrangements, please see Note 8, “Debt,” to our consolidated financial statements appearing in Item 8 of this report.
 
At February 22, 2011, we had no letters of credit outstanding under our credit facility. We had outstanding borrowings of $260 million under our credit facility and $61 million outstanding under our money market lines of credit. Our available borrowing capacity under our credit arrangements was approximately $1.03 billion as of February 22, 2011.
 
Working Capital.  Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements and changes in the fair value of our outstanding commodity derivative instruments. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital. Although we anticipate that our 2011 capital spending (excluding acquisitions) will correspond with our anticipated 2011 cash flows from operations, we may borrow and repay funds under our credit arrangements throughout the year since the timing of expenditures and the receipt of cash flows from operations do not necessarily match.
 
At December 31, 2010, we had negative working capital of $197 million. The decrease in our working capital as compared to December 31, 2009 is primarily due to a $123 million decrease in net derivative assets and the related deferred taxes resulting from the continued volatility of oil and gas prices and the settlement of our derivative contracts during 2010. In addition, working capital fluctuates due to the timing of receivable collections from purchasers and joint interest partners, drilling activities, payments made by us to vendors and other operators and the timing and amount of advances paid to and received from our joint operators.
 
At December 31, 2009, we had positive working capital of $20 million. The decrease in our working capital balance as compared to December 31, 2008 is primarily due to a $396 million decrease in net derivative assets and their related deferred taxes resulting from the settlement of our derivative contracts during 2009, partially offset by the timing of receivable collections from purchasers, payments made by us to vendors and other operators, and the timing and amount of advances received from our joint operations.
 
Cash Flows from Operations.  Cash flows from operations are primarily affected by production and commodity prices, net of the effects of settlements of our derivative contracts and changes in working capital. We sell substantially all of our oil and gas production under floating price market sensitive contracts. We generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12-24 months. See “— Oil and Gas Hedging” below.
 
We typically receive the cash associated with oil and gas sales within 45-60 days of production. As a result, cash flows from operations and income from operations generally correlate, but cash flows from operations are impacted by changes in working capital and are not affected by DD&A, ceiling test writedowns, other impairments, or other non-cash charges or credits.
 
Our net cash flows from operations were approximately $1.6 billion in 2010 and 2009. Our working capital requirements change each year as a result of the timing of receivable collections from purchasers and joint interest partners, drilling activities, payments made by us to vendors and other operators and the timing and amount of advances paid to and received from our joint operations. The positive impact of higher realized average commodity prices during 2010 on our cash flows from operations was offset by increased operating costs.
 
Our net cash flows from operations was $1.6 billion in 2009, an increase of 85% compared to net cash flows from operations of $854 million in 2008. This increase is primarily due to net cash receipts related to derivative settlements of $883 million during 2009 compared to net cash payments of $750 million during 2008. The net cash payments in 2008 included $558 million to reset our 2009 and 2010 crude oil hedging contracts effectively settling the liability on our balance sheet at that time. Our 2009 net cash flows from


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operations were negatively impacted by lower average realized commodity prices during the year. Our working capital requirements during 2009 increased compared to 2008 as a result of the timing of drilling activities, receivable collections from purchasers, payments made by us to vendors and other operators and the timing and amount of advances received from our joint operations.
 
Cash Flows from Investing Activities.  Net cash used in investing activities for 2010 was $2.0 billion compared to $1.4 billion for 2009.
 
During 2010, we:
 
  •  spent $2.0 billion primarily for additions to oil and gas properties (including $313 million for acquisitions of oil and gas properties);
 
  •  received proceeds of $12 million from sales of oil and gas properties; and
 
  •  redeemed investments of $8 million.
 
During 2009, we:
 
  •  spent $1.4 billion primarily for additions to oil and gas properties (including $9 million for acquisitions of oil and gas properties);
 
  •  received proceeds of $33 million from sales of oil and gas properties; and
 
  •  redeemed investments of $20 million.
 
Capital Expenditures.  Our capital spending of $2.0 billion for 2010 increased 40% from our capital spending of $1.4 billion during 2009. These amounts exclude recorded asset retirement obligations of $13 million and $19 million in the 2010 and 2009 periods, respectively. Of the $2.0 billion spent during 2010, we invested $1.2 billion in domestic exploitation and development, $248 million in domestic exploration (exclusive of exploitation and leasehold activity), $400 million in acquisitions of proved and unproved property (leasehold) and domestic leasing activity and $173 million outside the United States.
 
Our capital spending of $1.4 billion for 2009 decreased 38% from our $2.3 billion of capital spending during 2008. These amounts exclude recorded asset retirement obligations of $19 million in 2009 and $15 million in 2008. Of the $1.4 billion spent in 2009, we invested $937 million in domestic exploitation and development, $181 million in domestic exploration (exclusive of exploitation and leasehold activity), $147 million in acquisitions of proved and unproved property (leasehold) and domestic leasing activity and $148 million outside the United States.
 
We have budgeted $1.7 billion for capital spending in 2011. The planned budget excludes capitalized interest and overhead of $170 million. Approximately two-thirds of the 2011 budget will be allocated to oil projects and substantially all of the remainder is planned for “liquids rich” gas plays. See Items 1 and 2, “Business and Properties — Our Properties and Plans for 2011.” The 2011 capital budget is based on our expectation that we will live within anticipated cash flows from operations (excluding acquisitions). Actual levels of capital expenditures may vary significantly due to many factors, including drilling results, oil and gas prices, industry conditions, the prices and availability of goods and services and the extent to which properties are acquired. In addition, in the past, we often have increased our capital budget during the year as a result of acquisitions or successful drilling. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable.
 
Cash Flows from Financing Activities.  Net cash flows provided by financing activities for 2010 were $282 million compared to net cash flows used in financing activities of $168 million for 2009.
 
During 2010, we:
 
  •  borrowed $1.5 billion and repaid $1.7 billion under our credit arrangements;
 
  •  issued $700 million aggregate principal amount of 67/8% Senior Subordinated Notes due 2020 at 99.109% of par;
 
  •  paid $8 million in associated debt issue costs;


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  •  repaid our $175 million aggregate principal amount of 75/8% Senior Notes due 2011;
 
  •  received proceeds of $34 million from issuances of shares of our common stock upon the exercise of stock options; and
 
  •  repurchased $14 million of our common stock surrendered by employees to pay tax withholding upon the vesting of restricted stock and restricted stock unit awards.
 
During 2009, we:
 
  •  borrowed $1.0 billion and repaid $1.2 billion under our credit arrangements; and
 
  •  received proceeds of $9 million from issuances of shares of our common stock upon the exercise of stock options.
 
Proved Reserves
 
To maintain and grow our production and cash flow, we must continue to develop existing proved reserves and locate or acquire new oil and gas reserves to replace those reserves being produced. The following is a discussion of proved reserves, reserve additions and revisions and future net cash flows from proved reserves.
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (Bcfe)  
 
Proved Reserves:
                       
Beginning of year
    3,616       2,950       2,496  
Reserve additions
    676       1,342       758  
Reserve revisions
    (289 )     (384 )     (67 )
Sales
    (3 )     (35 )     (2 )
Production
    (288 )     (257 )     (235 )
                         
End of year
    3,712       3,616       2,950  
                         
Proved Developed Reserves:
                       
Beginning of year
    1,908       1,827       1,566  
End of year
    2,164       1,908       1,827  
 
Our proved natural gas reserves at year-end 2010 were 2.5 Tcf compared to 2.6 Tcf at year-end 2009 and 2.1 Tcf at year-end 2008. Our proved crude oil and condensate reserves at year-end 2010 were 204 million barrels compared to 169 million barrels at year-end 2009 and 140 million barrels at year-end 2008. Natural gas comprised approximately 67%, 72% and 72% of our proved reserves at year-end 2010, 2009 and 2008, respectively.
 
Reserve Additions and Revisions.  During 2010, we added 387 Bcfe net proved reserves as a result of additions (extensions, discoveries, improved recovery and purchases of reserves in place) and revisions, as described below. We expect the majority of future reserve additions to be associated with infill drilling, extensions of current fields and new discoveries, as well as improved recovery operations and purchases of proved properties. The success of these operations will directly impact reserve additions or revisions in the future.
 
Additions.  We added 676 Bcfe of proved reserves during 2010. Approximately 414 Bcfe of the additions resulted from successful development drilling, primarily in our Mid-Continent and Rocky Mountain divisions, where we added 322 Bcfe of proved undeveloped reserves primarily associated with our Woodford Shale, Williston Basin and Monument Butte fields. In addition, during 2010, extensions and other additions totaled 236 Bcfe, reflecting the shift in our investment strategy from natural gas to higher margin oil projects. During 2009, we added 1,342 Bcfe of proved reserves, approximately 521 Bcfe of which were as a result of successful drilling efforts in the Mid-Continent and Rocky Mountains divisions. During 2008, we added 758 Bcfe of


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proved reserves. Of this amount, 599 Bcfe was related to successful development drilling in our Mid-Continent and Rocky Mountain divisions.
 
Revisions.  Our revisions in 2010 include the reclassification of approximately 315 Bcfe of proved undeveloped reserves (nearly all Mid-Continent natural gas reserves) to probable reserves because a slower pace of development activity placed them beyond the five-year development horizon. This change reflects a shift in our investment strategy toward oil projects. Excluding this reclassification, our revisions were 26 Bcfe, consisting of positive price related revisions of 56 Bcfe, partially offset by 30 Bcfe of performance related revisions. Total revisions for 2009 were a negative 384 Bcfe, or 13% of the beginning of year reserve base. The revisions included a negative price revision of 259 Bcfe primarily related to our onshore natural gas plays, such as the Woodford Shale, and were primarily proven undeveloped reserves. The remaining 125 Bcfe of revisions in 2009 were negative performance revisions and were principally proved developed producing reserve revisions. Total revisions for 2008 were a negative 67 Bcfe and were primarily price related domestic revisions associated with the decrease in both year-end oil and gas prices from 2007 to 2008.
 
Sales.  In 2009, we sold approximately 35 Bcfe of reserves associated with our domestic operations. In 2010 and 2008, sales of reserves were negligible.
 
Future Net Cash Flows.  At December 31, 2010, the present value (discounted at 10%) of estimated future net cash flows from our proved reserves was $4.8 billion (stated in accordance with the regulations of the SEC and the Financial Accounting Standards Board (FASB). This present value was calculated based on the unweighted average first-day-of-the-month oil and gas prices for the prior twelve months held flat for the life of the reserves. The present value of our estimated future net cash flows at December 31, 2010, increased due to higher commodity prices as compared to the prior year, as well as shifting our strategy and capital toward oil projects in our portfolio which provide higher margins over natural gas investments. At December 31, 2009, the present value of estimated future net cash flows from our proved reserves was $2.9 billion. This amount is unchanged from the $2.9 billion at December 31, 2008 despite lower natural gas prices utilized to calculate 2009 proved reserves. Reserve quantity additions as a result of our drilling success during 2009 coupled with the additional reserve quantities recognized as a result of the SEC’s new reserves rules offset the impact of the lower natural gas prices utilized to calculate 2009 proved reserves. See “Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves” under Item 8 of this report.
 
The present value of future net cash flows does not purport to be an estimate of the fair market value of our proved reserves. An estimate of fair market value would also take into account, among other things, anticipated changes in future prices and costs, the expected recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money to the evaluating party and the perceived risks inherent in producing oil and gas.


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Contractual Obligations
 
The table below summarizes our significant contractual obligations by maturity as of December 31, 2010.
 
                                         
          Less than
                More than
 
    Total     1 Year     1-3 Years     4-5 Years     5 Years  
    (In millions)  
 
Debt:
                                       
Revolving credit facility
  $ 100     $     $ 100     $     $  
Money market lines of credit
    35             35              
65/8% Senior Subordinated Notes due 2014
    325                   325        
65/8% Senior Subordinated Notes due 2016
    550                         550  
71/8% Senior Subordinated Notes due 2018
    600                         600  
67/8% Senior Subordinated Notes due 2020
    700                         700  
                                         
Total debt
    2,310             135       325       1,850  
                                         
Other obligations:
                                       
Interest payments(1)
    1,065       151       298       275       341  
Net derivative (assets) liabilities
    (137 )     (145 )     8              
Asset retirement obligations
    108       11       16       21       60  
Operating leases(2)
    263       103       110       23       27  
Deferred acquisition payments
    2       2                    
Firm transportation
    567       55       140       136       236  
Oil and gas activities(3)
    65                          
                                         
Total other (assets) obligations
    1,933       177       572       455       664  
                                         
Total contractual (assets) obligations
  $ 4,243     $ 177     $ 707     $ 780     $ 2,514  
                                         
 
 
(1) Interest associated with our revolving credit facility and money market lines of credit was calculated using a weighted-average interest rate of 1.242% at December 31, 2010 and is included through the maturity of the facility.
 
(2) Includes non-cancellable agreements for office space and cancellable agreements for drilling rigs and other equipment, as well as certain service contracts. The majority of these obligations were executed in the fourth quarter of 2010 and are related to contracts for hydraulic well fracturing services and drilling rigs. Payments under these contracts are accounted for as capital additions to our oil and gas properties.
 
(3) As is common in the oil and gas industry, we have various contractual commitments pertaining to exploration, development and production activities. We have work-related commitments for, among other things, drilling wells, obtaining and processing seismic data and fulfilling other related commitments. At December 31, 2010, these work-related commitments totaled $65 million, all of which were attributable to our international business. Actual amounts by maturity are not included because their timing cannot be accurately predicted.
 
We have various oil and gas production volume delivery commitments that are primarily related to operations in our Mid-Continent and Rocky Mountain divisions. Given the size of our proved natural gas and oil reserves and production capacity in the respective divisions, we currently believe that we have sufficient reserves and production to fulfill these commitments. See Items 1 and 2, “Business and Properties” for a description of our production and proved reserves. As of December 31, 2010, our delivery commitments through 2018 were as follows:
 
                                         
        Less than
          More than
    Total   1 Year   1-3 Years   4-5 Years   5 Years
 
Natural gas (MMMBtus)
    52,496       34,196       18,300              
Oil (MBbls)
    10,958       913       2,740       3,650       3,655  


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Credit Arrangements.  Please see “— Liquidity and Capital Resources — Credit Arrangements” above for a description of our revolving credit facility and money market lines of credit.
 
Senior Subordinated Notes
 
In August 2004, we issued $325 million aggregate principal amount of our 65/8% Senior Subordinated Notes due 2014. The net proceeds from the offering were $323 million.
 
In April 2006, we issued $550 million aggregate principal amount of our 65/8% Senior Subordinated Notes due 2016. The net proceeds from the offering were $545 million.
 
In May 2008, we issued $600 million aggregate principal amount of our 71/8% Senior Subordinated Notes due 2018. We received net proceeds from the offering of $592 million.
 
In January 2010, we issued $700 million aggregate principal amount of our 67/8% Senior Subordinated Notes due 2020. We received net proceeds from the offering of $686 million.
 
Interest on our senior subordinated notes is payable semi-annually. The notes are unsecured senior subordinated obligations that rank junior in right of payment to all of our present and future senior indebtedness.
 
We may redeem some or all of our 65/8% notes due 2014 at any time on or after September 1, 2009 and some or all of our 65/8% notes due 2016 at any time on or after April 15, 2011, in each case, at a redemption price stated in the applicable indenture governing the notes. We also may redeem all but not part of our 65/8% notes due 2016 prior to April 15, 2011, at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption.
 
We may redeem some or all of our 71/8% notes at any time on or after May 15, 2013 at a redemption price stated in the indenture governing the notes. Prior to May 15, 2013, we may redeem all, but not part, of our 71/8% notes at a redemption price based on a make-whole amount plus accrued and unpaid interest to the date of redemption. In addition, before May 15, 2011, we may redeem up to 35% of the original principal amount of our 71/8% notes with the net cash proceeds of certain sales of our common stock at 107.125% of the principal amount, plus accrued and unpaid interest to the date of redemption.
 
We may redeem some or all of our 67/8% notes due 2020 at any time on or after February 1, 2015 at a redemption price stated in the indenture governing the notes. Prior to February 1, 2015, we may redeem some or all of the notes at a make-whole redemption price. In addition, before February 1, 2013, we may redeem up to 35% of our 67/8% notes with the net cash proceeds of certain sales of our common stock at 106.875% of the principal amount, plus accrued and unpaid interest to the date of redemption.
 
The indenture governing our senior subordinated notes may limit our ability under certain circumstances to, among other things:
 
  •  incur additional debt;
 
  •  make restricted payments;
 
  •  pay dividends on or redeem our capital stock;
 
  •  make certain investments;
 
  •  create liens;
 
  •  engage in transactions with affiliates; and
 
  •  engage in mergers, consolidations and sales and other dispositions of assets.
 
Commitments under Joint Operating Agreements.  Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the


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contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners, frequently without any identification as to the long-term nature of any commitments underlying such expenditures.
 
Oil and Gas Hedging
 
As part of our risk management program, we generally hedge a substantial, but varying, portion of our anticipated future oil and gas production for the next 12-24 months to reduce our exposure to fluctuations in oil and gas prices. In the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions. As of February 22, 2011, approximately 70% of our estimated 2011 domestic oil and gas production was subject to derivative contracts (including basis contracts). In 2010, approximately 70% of our domestic production was subject to derivative contracts, compared to 99% in 2009 and 82% in 2008.
 
While the use of these hedging arrangements limits the downside risk of adverse price movements, their use also may limit future revenues from favorable price movements. In addition, the use of hedging transactions may involve basis risk. All of our hedging transactions have been carried out in the over-the-counter market. The use of hedging transactions also involves the risk that the counterparties will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate hedging arrangements with that counterparty. At December 31, 2010, Barclays Capital, JPMorgan Chase Bank, N.A., Morgan Stanley, Bank of Montreal, J Aron & Company and Societe Generale were the counterparties with respect to 85% of our future hedged production, none of which were counterparty to more than 25% of our future hedged production.
 
A significant number of the counterparties to our hedging arrangements also are lenders under our credit facility. Our credit facility, senior subordinated notes and substantially all of our hedging arrangements contain provisions that provide for cross defaults and acceleration of those debt and hedging instruments in certain situations.
 
Substantially all of our hedging transactions are settled based upon reported settlement prices on the NYMEX. Historically, a majority of our hedged oil and gas production has been sold at market prices that have had a high positive correlation to the settlement price for such hedges.
 
The price that we receive for natural gas production from the Gulf of Mexico and onshore Gulf Coast, after basis differentials, transportation and handling charges, typically averages $0.25-$0.50 per MMBtu less than the Henry Hub Index. Realized natural gas prices for our Mid-Continent properties, after basis differentials, transportation and handling charges, typically average 85-90% of the Henry Hub Index. In the Rocky Mountains, we hedged basis associated with approximately 10 Bcf of our natural gas production from January 2011 through December 2012 to lock in the differential at a weighted average of $0.93 per MMBtu less than the Henry Hub Index. In total, this hedge and the 8,000 MMBtus per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.92 per MMBtu less than the Henry Hub Index. In the Mid-Continent, we hedged basis associated with approximately 5 Bcf of our anticipated Stiles/Britt Ranch natural gas production from January 2011 through August 2011. In total, this hedge and the 30,000 MMBtus per day we have sold on a fixed physical basis for the same period results in an average basis hedge of $0.52 per MMBtu less than the Henry Hub Index. We have also hedged basis associated with


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approximately 23 Bcf of our natural gas production from this area for the period September 2011 through December 2012 at an average of $0.55 per MMBtu less than the Henry Hub Index.
 
The price we receive for our Gulf Coast oil production, excluding NGLs, typically averages about 93-97% of the NYMEX West Texas Intermediate (WTI) price. The price we receive for our oil production in the Rocky Mountains, excluding NGLs, is currently averaging about $15-$17 per barrel below the WTI price. Oil production from our Mid-Continent properties, excluding NGLs, typically averages 90-95% of the WTI price. Oil sales from our operations in Malaysia typically sell at a slight discount to Tapis, or currently about 105-110% of WTI. Oil sales from our operations in China typically sell at $4-$6 per barrel less than the WTI price.
 
Please see the discussion and tables in Note 4, “Derivative Financial Instruments,” to our consolidated financial statements appearing later in this report for a description of the accounting applicable to our hedging program, a listing of open contracts as of December 31, 2010 and the estimated fair market value of those contracts as of that date. Between January 1, 2011 and February 22, 2011, we did not enter into any derivative contracts.
 
Off-Balance Sheet Arrangements
 
We do not currently utilize any off-balance sheet arrangements with unconsolidated entities to enhance liquidity and capital resource positions, or for any other purpose. However, as is customary in the oil and gas industry, we have various contractual work commitments as described above under “— Contractual Obligations.”
 
Critical Accounting Policies and Estimates
 
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect our reported results of operations and the amount of reported assets, liabilities and proved oil and gas reserves. Some 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 we believe are 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. Described below are the most significant policies we apply in preparing our financial statements, some of which are subject to alternative treatments under generally accepted accounting principles. We also describe the most significant estimates and assumptions we make in applying these policies. We discussed the development, selection and disclosure of each of these with the Audit Committee of our Board of Directors. See “— Results of Operations” above and Note 1, “Organization and Summary of Significant Accounting Policies,” to our consolidated financial statements for a discussion of additional accounting policies and estimates we make.
 
For discussion purposes, we have divided our significant policies into four categories. Set forth below is an overview of each of our significant accounting policies by category.
 
  •  We account for our oil and gas activities under the full cost method.  This method of accounting requires the following significant estimates:
 
  •  quantity of our proved oil and gas reserves;
 
  •  costs withheld from amortization; and
 
  •  future costs to develop and abandon our oil and gas properties.
 
  •  Accounting for business combinations requires estimates and assumptions regarding the fair value of the assets and liabilities of the acquired company.


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  •  Accounting for commodity derivative activities requires estimates and assumptions regarding the fair value of derivative positions.
 
  •  Stock-based compensation cost requires estimates and assumptions regarding the grant date fair value of awards, the determination of which requires significant estimates and subjective judgments.
 
Oil and Gas Activities.  Accounting for oil and gas activities is subject to special, unique rules. Two generally accepted methods of accounting for oil and gas activities are available — successful efforts and full cost. 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 unsuccessful exploration costs to be expensed, 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, while 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 the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, costs in effect at year-end and a 10% discount rate.
 
On December 31, 2008, the SEC issued “Modernization of Oil and Gas Reporting” (Final Rule). The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Forms 10-K for years ending on or after December 31, 2009. On January 6, 2010, the FASB issued Accounting Standards Update No. 2010-03, “Oil and Gas Reserve Estimation and Disclosures” (ASU 2010-03), which aligns the oil and gas reserve estimation and disclosure requirements of FASB Accounting Standards Codification Topic 932, “Extractive Industries — Oil and Gas” (Topic 932), with the requirements in the SEC’s Final Rule.
 
We adopted the Final Rule and ASU 2010-03 effective December 31, 2009. The following critical accounting policies and estimates discussions reflect the new rules unless stated otherwise. See “New Accounting Requirements” below for a full discussion.
 
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 cost centers (the amortization base) that are established on a country-by-country basis. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs and delay rentals. Capitalized costs also include salaries, employee benefits, costs of consulting services and other expenses that are estimated to directly relate to our oil and gas activities. Interest costs related to unproved properties also are capitalized. Although some of these costs will ultimately result in no additional reserves, we expect the benefits of successful wells to more than offset the costs of any unsuccessful ones. Costs associated with production and general corporate activities are expensed in the period incurred. The capitalized costs of our oil and gas properties, plus an estimate of our future development costs, are amortized on a unit-of-production method based on our estimate of total proved reserves. Amortization is calculated separately on a country-by-country basis. 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.
 
Proved Oil and Gas Reserves.  Our engineering estimates of proved oil and gas reserves directly impact financial accounting estimates, including depreciation, depletion and amortization expense and the full cost ceiling limitation. Proved oil and gas reserves are the estimated quantities of oil and gas reserves that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials and 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. 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


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economic conditions. Changes in oil and gas prices, operating costs and expected performance from a given reservoir also will result in future revisions to the amount of our estimated proved reserves. All reserve information in this report is based on estimates prepared by our petroleum engineering staff.
 
Depreciation, Depletion and Amortization.  Estimated proved oil and gas reserves are a significant component of our calculation of DD&A expense and revisions in such estimates may alter the rate of future expense. Holding all other factors constant, if reserves are revised upward, earnings would increase due to lower depletion expense. Likewise, if reserves are revised downward, earnings would decrease due to higher depletion expense or due to a ceiling test writedown. To change our domestic DD&A rate by $0.10 per Mcfe for the year ended December 31, 2010 would have required a change in the estimate of our domestic proved reserves of approximately 5%, or 170 Bcfe. To change our Malaysia DD&A rate by $0.10 per Mcfe for the year ended December 31, 2010 would have required a change in the estimate of our proved reserves in Malaysia of approximately 3%, or 5 Bcfe. Since production from our China operations is immaterial, any change in the DD&A rate as a result of changes in our proved reserves in China would not have materially affected our consolidated results of operations.
 
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. If net capitalized costs exceed the applicable cost center ceiling, we are subject to a ceiling test writedown 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 ceiling limitation is applied separately for each country in which we have oil and gas properties. The discounted present value of our proved reserves is a major component of the ceiling calculation and represents the component that requires the most subjective judgments. The ceiling value of oil and gas reserves is calculated based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, and costs in effect as of the last day of the quarter. The full cost ceiling test impairment calculation also takes into consideration the effects of hedging contracts that are designated for hedge accounting, if any.
 
At December 31, 2010, the ceiling value of our oil and gas reserves was calculated based on the unweighted average first-day-of-the-month commodity prices for the prior twelve months of $4.38 per MMBtu for natural gas and $79.42 per barrel for oil, adjusted for market differentials. Using these prices, the ceiling exceeded the net capitalized costs of our domestic oil and gas properties by approximately $1.5 billion (net of tax) at December 31, 2010. Holding all other factors constant, if the applicable unweighted average first-day-of-the-month commodity prices for the prior twelve months for both oil and gas were to decline approximately 10% from prices used at December 31, 2010, the excess of our domestic cost center ceiling over our capitalized costs would be reduced by approximately 50%.
 
At December 31, 2010, the Malaysia and China cost center ceilings exceeded the net capitalized costs of oil and gas properties by approximately $251 million and $45 million (net of tax), respectively. Holding all other factors constant, it is possible that we could experience a ceiling test writedown in Malaysia and China if the applicable unweighted average first-day-of-the-month oil price declined approximately 35% and 25%, respectively, from prices used at December 31, 2010.
 
At March 31, 2009, prior to our adoption of the Final Rule and ASU 2010-03, the ceiling value of our reserves was calculated based upon quoted period-end market prices of $3.63 per MMBtu for natural gas and $49.65 per barrel for oil, adjusted for market differentials. Using these prices, the unamortized net capitalized costs of our domestic oil and gas properties at March 31, 2009 exceeded the ceiling amount by approximately $1.3 billion ($854 million, after-tax), resulting in a ceiling test writedown.
 
At December 31, 2008, the ceiling value of our reserves was calculated based upon quoted period-end market prices of $5.71 per MMBtu for natural gas and $44.61 per barrel for oil, adjusted for market differentials. Using these prices, the unamortized net capitalized costs of our domestic oil and gas properties exceeded the ceiling amount by approximately $1.7 billion ($1.1 billion, after-tax) at December 31, 2008. In addition, the unamortized net capitalized costs of our Malaysian properties exceeded the ceiling amount by approximately $71 million ($68 million, after-tax) at December 31, 2008. The ceiling with respect to our


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properties in China exceeded the net capitalized costs of the properties, requiring no writedown at December 31, 2008.
 
Given the fluctuation of oil and gas prices, it is reasonably possible that the estimated discounted future net cash flows from our proved reserves will change in the near term. If the unweighted average first-day-of-the-month commodity prices for the prior twelve months decline, or if we have downward revisions to our estimated proved reserves, it is possible that additional writedowns of our oil and gas properties could occur in the future.
 
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 and seismic data, wells currently drilling and capitalized interest are initially excluded from our amortization base. Leasehold costs are either transferred to our amortization base with the costs of drilling a well on the lease or are assessed quarterly for possible impairment or reduction in value. Leasehold costs are transferred to our amortization base to the extent a reduction in value has occurred or a charge is made against earnings if the costs were incurred in a country for which a reserve base has not been established. If a reserve base for a country in which we are conducting operations has not yet been established, an impairment requiring a charge to earnings may be indicated through evaluation of drilling results, relinquishing drilling rights or other information.
 
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, we had a total of approximately $1.7 billion of costs excluded from the amortization base of our respective full cost pools. The application of the full cost ceiling test at December 31, 2010 resulted in an excess of the cost center ceilings over the carrying value of our oil and gas properties for each full cost pool. Holding all other factors constant, inclusion of substantially all of our domestic unevaluated property costs in the amortization base would not have resulted in a ceiling test writedown. Including all of our Malaysian unevaluated property costs in our Malaysia amortization base would not have resulted in a ceiling test writedown. Holding all other factors constant, inclusion of approximately 60% of our unevaluated property costs in China into the amortization base of that country would have resulted in a ceiling test writedown.
 
Future Development and Abandonment Costs.  Future development costs include costs incurred to obtain access to proved reserves such as drilling costs and the installation of production equipment. Future abandonment costs include costs to dismantle and relocate or dispose of our production platforms, gathering systems and related structures and restoration costs of land and seabed. We develop estimates of these costs for each of our properties based upon their geographic location, type of production structure, water depth, reservoir depth and characteristics, market demand for equipment, 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 abandonment costs on an annual basis, or more frequently if an event occurs or circumstances change that would affect our assumptions and estimates.
 
The accounting guidance for future abandonment costs 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


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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 development and abandonment 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. To change our domestic DD&A rate by $0.10 per Mcfe for the year ended December 31, 2010 would have required a change in the estimate of our domestic future development and abandonment costs of approximately 10%, or $340 million. To change our Malaysia DD&A rate by $0.10 per Mcfe for the year ended December 31, 2010 would have required a change in the estimate of our future development and abandonment costs in Malaysia of approximately 8%, or $17 million. Since production from our China operations is immaterial, any change in the DD&A rate as a result of changes in the estimate of our future development and abandonment costs in China would not have materially affected our consolidated results of operations.
 
Allocation of Purchase Price in Business Combinations.  As part of our growth strategy, we monitor and screen for potential acquisitions of oil and gas properties. The purchase price in an acquisition is allocated to the assets acquired and liabilities assumed based on their relative fair values as of the acquisition date, which may occur many months after the announcement date. Therefore, while the consideration to be paid may be fixed, the fair value of the assets acquired and liabilities assumed is subject to change during the period between the announcement date and the acquisition date. Our most significant estimates in our allocation typically relate to the value assigned to future recoverable oil and gas reserves and unproved properties. To the extent the consideration paid exceeds the fair value of the net assets acquired, we are required to record the excess as an asset called goodwill. As the allocation of the purchase price is subject to significant estimates and subjective judgments, the accuracy of this assessment is inherently uncertain. The value allocated to recoverable oil and gas reserves and unproved properties is subject to the cost center ceiling as described under “— Full Cost Ceiling Limitation” above. The accounting for business combinations changed effective January 1, 2009 and established how a purchaser recognizes and measures in its financial statements the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree. The standard also sets forth guidance related to the recognition, measurement and disclosure related to goodwill acquired in a business combination or gains associated with a bargain purchase transaction. The standard applies prospectively to business combinations for which the acquisition date is on or after December 31, 2008. We adopted the standard effective January 1, 2009.
 
Commodity Derivative Activities.  We utilize derivative contracts to hedge against the variability in cash flows associated with the forecasted sale of our future oil and gas production. We generally hedge a substantial, but varying, portion of our anticipated oil and gas production for the next 12-24 months. In the case of acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between the NYMEX Henry Hub posted prices and those of our physical pricing points. We do not use derivative instruments for trading purposes. Under accounting rules, we may elect to designate those derivatives that qualify for hedge accounting as cash flow hedges against the price that we will receive for our future oil and gas production. Since late 2005, we have not designated future price risk management activities as accounting hedges. Because derivative contracts not designated for hedge accounting are accounted for on a mark-to-market basis, we are likely to experience significant non-cash volatility in our reported earnings during periods of commodity price volatility. Derivative assets and liabilities with the same counterparty and subject to contractual terms which provide for net settlement are reported on a net basis on our consolidated balance sheet.
 
In determining the amounts to be recorded for our open hedge contracts, we are required to estimate the fair value of the derivative. Our valuation models for derivative contracts are primarily industry-standard models that consider various inputs including: (a) quoted forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments, as well as other relevant economic measures. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the prices fixed by the hedge agreements and the resulting estimated future cash inflows or outflows over the lives of the hedges are discounted to calculate the fair value of the derivative contracts. These pricing and


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discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. We periodically validate our valuations using independent, third-party quotations.
 
The determination of the fair values of derivative instruments incorporates various factors which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties.
 
Stock-Based Compensation.  We apply a fair value-based method of accounting for stock-based compensation which requires recognition in the financial statements of the cost of services received in exchange for awards of equity instruments based on the grant date fair value of those awards. For equity-based compensation awards, compensation expense is based on the fair value on the date of grant or modification, and is recognized in our financial statements over the vesting period. We utilize the Black-Scholes option pricing model to measure the fair value of stock options and a lattice-based model for our performance and market-based restricted stock. See Note 10, “Stock-Based Compensation,” to our consolidated financial statements for a full discussion of our stock-based compensation.
 
New Accounting Requirements
 
In March 2008, the FASB issued guidance requiring enhanced disclosures about our derivative and hedging activities that was effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted the disclosure requirements beginning January 1, 2009. Please see Note 4, “Derivative Financial Instruments — Additional Disclosures about Derivative Instruments and Hedging Activities.” The adoption did not have an impact on our financial position or results of operations.
 
In April 2009, the FASB issued additional guidance regarding fair value measurements and impairments of securities which makes fair value measurements more consistent with fair value principles, enhances consistency in financial reporting by increasing the frequency of fair value disclosures, and provides greater clarity and consistency in accounting for and presenting impairment losses on securities. The additional guidance was effective for interim and annual periods ending after June 15, 2009, with early adoption permitted for periods ending after March 15, 2009. We adopted the provisions for the period ended March 31, 2009. The adoption did not have a material impact on our financial position or results of operations.
 
In May 2009, the FASB established general standards of accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued or are available to be issued. Although there is new terminology, the guidance is based on the same principles as those that previously existed. This guidance was effective for interim or annual periods ending after June 15, 2009. Our adoption of these provisions beginning with the period ended June 30, 2009 did not have an impact on our financial position or results of operations.
 
On December 31, 2008, the SEC issued the Final Rule. The Final Rule adopts revisions to the SEC’s oil and gas reporting disclosure requirements and is effective for annual reports on Form 10-K for years ending on or after December 31, 2009. The revisions were intended to provide investors with a more meaningful and comprehensive understanding of oil and gas reserves to help investors evaluate their investments in oil and gas companies. The amendments were also designed to modernize the oil and gas disclosure requirements to align them with current practices and changes in technology.
 
On January 6, 2010, the FASB issued ASU 2010-03, which aligned the FASB’s oil and gas reserve estimation and disclosure requirements with the requirements in the SEC’s Final Rule. We adopted the Final Rule and ASU 2010-03 effective December 31, 2009 as a change in accounting principle that is inseparable from a change in accounting estimate. Such a change was accounted for prospectively under the authoritative accounting guidance. Comparative disclosures applying the new rules for periods before the adoption of ASU 2010-03 and the Final Rule were not required.


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Our adoption of ASU 2010-03 and the Final Rule on December 31, 2009 impacted our financial statements and other disclosures in our annual report on Form 10-K for the years ended December 31, 2010 and 2009, as follows:
 
  •  All oil and gas reserves volumes presented as of and for the years ended December 31, 2010 and 2009 were prepared using the updated reserves rules and are not on a basis comparable with the prior period. This change in comparability occurred because we estimated our proved reserves at December 31, 2010 and 2009 using the updated reserves rules, which require use of the unweighted average first-day-of-the-month commodity prices for the prior twelve months, adjusted for market differentials, and permits the use of reliable technologies to support reserve estimates. Under the previous reserve estimation rules, which are no longer in effect, our net proved oil and gas reserves would have been calculated using end of period oil and gas prices. In addition, the new rules permit us to disclose probable reserves (and we have so disclosed probable reserves), which was not permitted under previous rules.
 
  •  Our full-cost ceiling test calculations at December 31, 2010 and 2009 used discounted cash flow models for our estimated proved reserves, which were calculated using the updated reserves rules.
 
  •  We historically have applied a policy of using our year-end proved reserves to calculate our fourth quarter depletion rate. As a result, the estimate of proved reserves for determining our depletion rate and resulting expense for the fourth quarter of 2009 and subsequent quarters is not on a basis comparable to the prior quarters or the prior year.
 
On April 20, 2010, the FASB issued Accounting Standards Update No. 2010-14, “Accounting for Extractive Industries — Oil and Gas” (ASU 2010-14), which aligned the oil and gas financial accounting and reporting requirements prescribed by Topic 932 with the requirements in the SEC’s Final Rule. The adoption of ASU 2010-14 did not have a material impact on our financial position or results of operations.
 
In January 2010, the FASB issued additional disclosure requirements related to fair value measurements. The guidance requires disclosure of transfers of assets and liabilities between Level 1 and Level 2 in the fair value measurement hierarchy, including the reasons for the transfers and disclosure of major purchases, sales, issuances, and settlements on a gross basis in the reconciliation of the assets and liabilities measured under Level 3 of the fair value measurement hierarchy. The guidance is effective for interim and annual periods beginning after December 15, 2009, except for the Level 3 reconciliation disclosures which are effective for interim and annual periods beginning after December 15, 2010. We adopted the provisions for the quarter ended March 31, 2010, except for the Level 3 reconciliation disclosures, which we will adopt for the quarter ending March 31, 2011. Adopting the disclosure requirements did not have an impact on our financial position or results of operations. We do not expect adoption of the Level 3 reconciliation disclosures in 2011 to have an impact on our financial position or results of operations.
 
Regulation
 
Exploration and development and the production and sale of oil and gas are subject to extensive federal, state, local and international regulations. An overview of these regulations is set forth in Items 1 and 2, “Business and Properties — Regulation.” We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. Please see the discussion under the caption “We are subject to complex laws that can affect the cost, manner or feasibility of doing business,” in Item 1A of this report.


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Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
We are exposed to market risk from changes in oil and gas prices, interest rates and foreign currency exchange rates as discussed below.
 
Oil and Gas Prices
 
We generally hedge a substantial, but varying, portion of our anticipated oil and gas production for the next 12-24 months as part of our risk management program. In the case of significant acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize basis contracts to hedge the differential between NYMEX Henry Hub posted prices and those of our physical pricing points. We use hedging to reduce our exposure to fluctuations in oil and gas prices. Reducing our exposure to price volatility helps ensure that we have adequate funds available for our capital programs and helps us manage returns on some of our acquisitions and more price sensitive drilling programs. Our decision on the quantity and price at which we choose to hedge our production is based in part on our view of current and future market conditions. While hedging limits the downside risk of adverse price movements, it also may limit future revenues from favorable price movements. The use of hedging transactions also involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. For a further discussion of our hedging activities, see the information under the caption “Oil and Gas Hedging” in Items 1 and 2 of this report and the discussion and tables in Note 4, “Derivative Financial Instruments,” to our consolidated financial statements.
 
Interest Rates
 
At December 31, 2010, our debt was comprised of:
 
                 
    Fixed
    Variable
 
    Rate Debt     Rate Debt  
    (In millions)  
 
Bank revolving credit facility
  $     $ 100  
Money market lines of credit
          35  
65/8% Senior Subordinated Notes due 2014
    325        
65/8% Senior Subordinated Notes due 2016
    550        
71/8% Senior Subordinated Notes due 2018
    600        
67/8% Senior Subordinated Notes due 2020
    694        
                 
Total debt
  $ 2,169     $ 135  
                 
 
We consider our interest rate exposure to be minimal because approximately 94% of our obligations were at fixed rates.
 
 
The functional currency for all of our foreign operations is the U.S. dollar. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, we are exposed to foreign currency exchange risk. We consider our current risk exposure to exchange rate movements, based on net cash flow, to be immaterial. We did not have any open derivative contracts relating to foreign currencies at December 31, 2010.


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Item 8.   Financial Statements and Supplementary Data
 
NEWFIELD EXPLORATION COMPANY
 
INDEX
 
CONSOLIDATED FINANCIAL STATEMENTS
AND SUPPLEMENTARY DATA
 
         
    Page
 
Management’s Report on Internal Control over Financial Reporting
    58  
Report of Independent Registered Public Accounting Firm
    59  
Consolidated Balance Sheet as of December 31, 2010 and 2009
    60  
Consolidated Statement of Income for each of the three years in the period ended December 31, 2010
    61  
Consolidated Statement of Stockholders’ Equity for each of the three years in the period ended December 31, 2010
    62  
Consolidated Statement of Cash Flows for each of the three years in the period ended December 31, 2010
    63  
Notes to Consolidated Financial Statements
    64  
Supplementary Financial Information — Supplementary Oil and Gas Disclosures — Unaudited
    99  


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MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
 
Our company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles. Under the supervision and with the participation of our company’s management, including the Chief Executive Officer and the Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
Our internal control over financial reporting includes those policies and procedures that: (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of our assets; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of our financial statements in accordance with generally accepted accounting principles, and that our receipts and expenditures are being made only in accordance with authorizations of our management and directors; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our 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.
 
Based on our evaluation under the framework in Internal Control — Integrated Framework, the management of our company concluded that our internal control over financial reporting was effective as of December 31, 2010.
 
The effectiveness of our internal control over financial reporting as of December 31, 2010 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report that follows.
 
     
-s- Lee K. Boothby   -s- Terry W. Rathert
Lee K. Boothby
  Terry W. Rathert
President and Chief Executive Officer
  Executive Vice President and Chief Financial Officer
 
Houston, Texas
February 25, 2011


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Stockholders of Newfield Exploration Company
 
In our opinion, the accompanying consolidated balance sheet and the related consolidated statements of income, of stockholders’ equity and of cash flows present fairly, in all material respects, the financial position of Newfield Exploration Company and its subsidiaries 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 the accompanying Management’s Report on Internal Control over Financial Reporting. 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 1 to the consolidated financial statements, the Company changed the manner in which it estimates the quantities of oil and gas reserves in 2009 due to the adoption of Accounting Standards Update No. 2010-03, Oil and Gas Reserve Estimation and Disclosures.
 
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.
 
(PRICEWATERSHOUSECOOPERS LOGO)
 
Houston, Texas
February 25, 2011


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NEWFIELD EXPLORATION COMPANY
 
(In millions, except share data)
 
                 
    December 31,  
    2010     2009  
 
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 39     $ 78  
Accounts receivable
    354       339  
Inventories
    79       84  
Derivative assets
    197       269  
Other current assets
    62       123  
                 
Total current assets
    731       893  
                 
Property and equipment, at cost, based on the full cost method of accounting for oil and gas properties ($1,658 and $1,223 were excluded from amortization at December 31, 2010 and 2009, respectively)
    12,399       10,406  
Less — accumulated depreciation, depletion and amortization
    (5,791 )     (5,159 )
                 
Total property and equipment, net
    6,608       5,247  
                 
Derivative assets
    39       19  
Long-term investments
    48       55  
Deferred taxes
    29       26  
Other assets
    39       14  
                 
Total assets
  $ 7,494     $ 6,254  
                 
 
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 92     $ 83  
Accrued liabilities
    670       640  
Advances from joint owners
    51       51  
Asset retirement obligation
    11       10  
Derivative liabilities
    53       2  
Deferred taxes
    51       87  
                 
Total current liabilities
    928       873  
                 
Other liabilities
    56       55  
Derivative liabilities
    46       5  
Long-term debt
    2,304       2,037  
Asset retirement obligation
    97       82  
Deferred taxes
    720       434  
                 
Total long-term liabilities
    3,223       2,613  
                 
Commitments and contingencies (Note 13)
           
Stockholders’ equity:
               
Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)
           
Common stock ($0.01 par value, 200,000,000 shares authorized at December 31, 2010 and 2009; 135,910,641 and 134,493,670 shares issued at December 31, 2010 and 2009, respectively)
    1       1  
Additional paid-in capital
    1,450       1,389  
Treasury stock (at cost, 1,664,538 and 1,488,968 shares at December 31, 2010 and 2009, respectively)
    (41 )     (33 )
Accumulated other comprehensive loss
    (12 )     (11 )
Retained earnings
    1,945       1,422  
                 
Total stockholders’ equity
    3,343       2,768  
                 
Total liabilities and stockholders’ equity
  $ 7,494     $ 6,254  
                 
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


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NEWFIELD EXPLORATION COMPANY
 
(In millions, except per share data)
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Oil and gas revenues
  $ 1,883     $ 1,338     $ 2,225  
                         
Operating expenses:
                       
Lease operating
    326       259       265  
Production and other taxes
    126       63       157  
Depreciation, depletion and amortization
    644       587       697  
General and administrative
    156       144       141  
Ceiling test and other impairments
    7       1,344       1,863  
Other
    10       8       4  
                         
Total operating expenses
    1,269       2,405       3,127  
                         
Income (loss) from operations
    614       (1,067 )     (902 )
                         
Other income (expenses):
                       
Interest expense
    (156 )     (126 )     (112 )
Capitalized interest
    58       51       60  
Commodity derivative income
    316       252       408  
Other
    (3 )     5       11  
                         
Total other income
    215       182       367  
                         
Income (loss) before income taxes
    829       (885 )     (535 )
                         
Income tax provision (benefit):
                       
Current
    59       48       36  
Deferred
    247       (391 )     (198 )
                         
Total income tax provision (benefit)
    306       (343 )     (162 )
                         
Net income (loss)
  $ 523     $ (542 )   $ (373 )
                         
Earnings (loss) per share:
                       
Basic
  $ 3.97     $ (4.18 )   $ (2.88 )
                         
Diluted
  $ 3.91     $ (4.18 )   $ (2.88 )
                         
Weighted-average number of shares outstanding for basic income (loss) per share
    132       130       129  
                         
Weighted-average number of shares outstanding for diluted income (loss) per share
    134       130       129  
                         
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


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NEWFIELD EXPLORATION COMPANY
 
(In millions)
 
                                                                 
                                        Accumulated
       
                            Additional
          Other
    Total
 
    Common Stock     Treasury Stock     Paid-in
    Retained
    Comprehensive
    Stockholders’
 
    Shares     Amount     Shares     Amount     Capital     Earnings     Income (Loss)     Equity  
 
Balance, December 31, 2007
    133.2     $ 1       (1.9 )   $ (32 )   $ 1,278     $ 2,337     $ (3 )   $ 3,581  
Issuances of common and restricted stock
    0.9                             20                       20  
Stock-based compensation
    (0.1 )                           37                       37  
Comprehensive income (loss):
                                                               
Net loss
                                            (373 )             (373 )
Unrealized loss on investments, net of tax of $6
                                                    (13 )     (13 )
Unrealized gain on post-retirement benefits, net of tax of ($3)
                                                    5       5  
                                                                 
Total comprehensive loss
                                                            (381 )
                                                                 
Balance, December 31, 2008
    134.0       1       (1.9 )     (32 )     1,335       1,964       (11 )     3,257  
Issuances of common and restricted stock
    0.5                             9                       9  
Stock-based compensation
                                    45                       45  
Treasury stock, at cost
                    0.4       (1 )                           (1 )
Comprehensive income (loss):
                                                               
Net loss
                                            (542 )             (542 )
Unrealized gain on investments, net of tax of ($1)
                                                    2       2  
Realized loss on post-retirement benefits, net of tax of $1
                                                    (2 )     (2 )
                                                                 
Total comprehensive loss
                                                            (542 )
                                                                 
Balance, December 31, 2009
    134.5       1       (1.5 )     (33 )     1,389       1,422       (11 )     2,768  
Issuances of common and restricted stock
    1.4                             34                       34  
Stock-based compensation
                                    33                       33  
Treasury stock, at cost
                    (0.2 )     (8 )     (6 )                     (14 )
Comprehensive income (loss):
                                                               
Net income
                                            523               523  
Unrealized loss on post-retirement benefits, net of tax
                                                    (1 )     (1 )
                                                                 
Total comprehensive income
                                                            522  
                                                                 
Balance, December 31, 2010
    135.9     $ 1       (1.7 )   $ (41 )   $ 1,450     $ 1,945     $ (12 )   $ 3,343  
                                                                 
 
The accompanying notes to consolidated financial statements are an integral part of this statement.


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NEWFIELD EXPLORATION COMPANY
 
(In millions)
 
 
                         
    Year Ended December 31,  
    2010     2009     2008  
 
Cash flows from operating activities:
                       
Net income (loss)
  $ 523     $ (542 )   $ (373 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                       
Depreciation, depletion and amortization
    644       587       697  
Deferred tax provision (benefit)
    247       (391 )     (198 )
Stock-based compensation
    22       28       26  
Commodity derivative income
    (316 )     (252 )     (408 )
Cash receipts (payments) on derivative settlements, net
    456       883       (750 )
Ceiling test and other impairments
    7