UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 20082009
or
oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from          to
Commission file number: 001-07964
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware 73-0785597
(State of incorporation) (I.R.S. employer identification number)
100 Glenborough Drive, Suite 100  
Houston, Texas 77067
(Address of principal executive offices) (Zip Code)

(281) 872-3100
(Registrant’s telephone number, including area code)

Securities registered pursuant to section 12(b) of the Act:
Title of each class Name of each exchange on which registered
Common Stock, $3.33-1/3 par value New York Stock Exchange
Preferred Stock Purchase Rights 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.
x Yes o No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
o Yes x No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. x Yes o No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. x
 
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 definitions of “accelerated“large accelerated filer”, “large accelerated“accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
                             (Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).o Yes x No

Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2008: $17.22009: $10.1 billion.
Number of shares of Common Stock outstanding as of February 6, 2009: 172,913,730.5, 2010: 174,444,080.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 20092010 Annual Meeting of Stockholders to be held on April 28, 2009,27, 2010, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2008,2009, are incorporated by reference into Part III.


 
 

TABLE OF CONTENTS

      Part I
Items 1 and 2.
Business and Properties.
12
Item 1A.
Risk FactorsFactors..
1920
Item 1B.
Unresolved Staff Comments.
2529
Item 3.
Legal Proceedings.
2529
Item 4.
Submission of Matters to a Vote of Security Holders.
2529
Executive Officers25
Part II
Item 5.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
2731
Item 6.
Selected Financial Data.
2933
Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations.
3034
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk.
5561
Item 8.
Financial Statements and Supplementary Data.
5663
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
108119
Item 9A.
Controls and Procedures.
108119
Item 9B.
Other Information.
108119
Part III
Item 10.
Directors, Executive Officers and Corporate Governance.
109120
Item 11.
Executive Compensation.
109120
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
109120
Item 13.
Certain Relationships and Related Transactions, and Director Independence
109120
Item 14.
Principal Accounting Fees and Services
109120
Part IV
Item 15.
Exhibits, Financial Statements Schedules
109120

 





PART I

Items 11. and 2.  Business and Properties
 
This Annual Report on Form 10-K and the documents incorporated herein by reference contain forward-looking statements based on expectations, estimates and projections as of the date of this filing. These statements by their nature are subject to risks, uncertainties and assumptions and are influenced by various factors. As a consequence, actual results may differ materially from those expressed in the forward-looking statements. For more information, seeSee Item 1A. Risk Factors—Factors – Disclosure Regarding Forward-Looking Statements of this Form 10-K.
 
General
 
Noble Energy, Inc. (Noble Energy, we or us) is a Delaware corporation, formed in 1969, that has been publicly traded on the New York Stock Exchange (NYSE) since 1980. We are an independent energy company that has been engaged in the acquisition, exploration, development, production and marketing of crude oil, natural gas, and natural gas liquids (NGLs) since 1932. In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy and its subsidiaries. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with key international operations offshore Israel the North Sea and West Africa.
Strategy
 
Our strategyaim is to achieve growth in earnings and cash flow through exploration success and the finding and development of a high quality portfolio of producing assets that is balanced between US and international projects. StrategicExploration success, along with additional capital investment, in US and international locations such as Equatorial Guinea and Israel, have resulted in substantial growth in the last several years. In addition, occasional strategic acquisitions ofsuch as Patina Oil & Gas Corporation (Patina) in 2005 and U.S. Exploration Holdings, Inc. (U.S. Exploration) in 2006, along with additional capital investment in US and international locations, have resulted in substantial growth in the last several years. Acquisitions and capital investment, combined with the sale of non-core assets, have allowed us to achieve a strategic objective of enhancing our US asset portfolio, resulting in a company with assets and capabilities that include growingmajor US basins coupled with a significant portfolio of international properties. See Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2004-2008.2005-2009.
In the current commodity and economic environment, our focus has remained on positioning Noble Energy for the future. In January 2009, we announced a significant discovery at Tamar, offshore Israel, the largest discovery in our history. Also during 2009, we made substantial progress on our significant portfolio of long-term growth projects, including the sanctioning of the oil development projects at Aseng (formerly Benita) offshore Equatorial Guinea and at Isabela/Santa Cruz (which we refer to collectively as Galapagos) in the deepwater Gulf of Mexico, as well as making important progress on our plans for the Tamar discovery.  These and other major development projects typically offer long life, sustained cash flows after investment and attractive financial returns. We also have significant remaining exploration potential, primarily in the deepwater Gulf of Mexico and offshore West Africa and Israel.
 
Proved ReservesMajor Development Project Inventory   
Proved reserves estimates at December 31, 2008 were as follows:Our exploration success has provided us with a number of significant development projects on which we are moving forward. These projects will require significant capital investments over the next several years.  Our major projects include the following:
 
  
December 31, 2008
 
  
Proved
  
Proved
  
Total
 
  
Developed
  
Undeveloped
  
Proved
 
  
Reserves
  
Reserves
  
Reserves
 
United States
         
Crude oil, condensate and NGLs (MMBbls)
  121   77   198 
Natural gas (Bcf)
  1,268   591   1,859 
Total US (MMBoe) (1)
  332   176   508 
International
            
Crude oil, condensate and NGLs (MMBbls)
  78   35   113 
Natural gas (Bcf)
  1,117   339   1,456 
Total International (MMBoe) (1)
  264   92   356 
Worldwide
            
Crude oil, condensate and NGLs (MMBbls)
  199   112   311 
Natural gas (Bcf)
  2,385   930   3,315 
Total Worldwide (MMBoe) (1) (2)
  596   268   864 
(1)
Natural gas is converted on the basis·
Galapagos (deepwater Gulf of six Mcf of gas per one barrel of oil equivalent.Mexico);
(2)
Approximately 69% are proved developed reserves.
·		Aseng (offshore West Africa);
·Tamar (offshore Israel);
Estimates of Proved Reserves – Proved oil and gas reserves
·Gunflint (deepwater Gulf of Mexico);
·Belinda (offshore West Africa); and
·Diega/Carmen (offshore West Africa).
These projects are discussed in more detail in the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. For additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved and proved developed reserves, the standardized measure of discounted future net cash flows, and the changes in discounted future net cash flows, seesections below. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Reserves and Item 8. Financial Statements and Supplementary Data—Supplemental Oil and Gas Information.Operations – Operating Outlook – Major Development Project Inventory.

 

12

Proved Oil and Gas Reserves    Proved reserves estimates at December 31, 2009 were as follows:
Summary of Oil and Gas Reserves as of Fiscal-Year End 
Based on Average Fiscal-Year Prices 
  December 31, 2009 
  Proved Reserves 
  Crude Oil, Condensate & NGLs  Natural Gas  
Total (1)
 
Reserves Category (MMBbls)  (Bcf)  (MMBoe) 
          
Proved Developed         
United States  122   1,114   307 
Equatorial Guinea  49   638   155 
Israel  -   191   32 
Other International  23   192   56 
Total Proved Developed Reserves  194   2,135   550 
Proved Undeveloped            
United States  87   420   157 
Equatorial Guinea  43   302   93 
Israel  -   43   7 
Other International  12   4   13 
Total Proved Undeveloped Reserves  142   769   270 
Total Proved Reserves  336   2,904   820 
 
Reserve Audit (1) Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent.
In December 2008, the Securities and Exchange Commission (SEC) announced that it had approved revisions to modernize its oil and gas company reserves reporting requirements. We adopted the new rules as of December 31, 2009.  See Proved Reserves Disclosures, below, for additional disclosures provided in accordance with the SEC’s rules for Modernization of Oil and Gas Reporting and Item 8. Financial Statements and Supplementary Data – EngineersSupplemental Oil and Gas Information (Unaudited) for definitions of proved oil and gas reserves, proved developed oil and gas reserves and proved undeveloped oil and gas reserves.

Crude Oil and Natural Gas Properties and Activities
We search for crude oil and natural gas properties, seek to acquire exploration rights in areas of interest and conduct exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which we have acquired exploration rights. Our properties consist primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. We also own natural gas processing plants and natural gas gathering and other crude oil and natural gas related pipeline systems which are primarily used in the processing and transportation of our crude oil, natural gas and NGL production.
Exploration Activities   We primarily focus on organic growth from exploration and development drilling, concentrating on basins or plays where we have strategic competitive advantage and which we believe offer superior returns. We have had substantial exploration success in the deepwater Gulf of Mexico, West Africa and the Eastern Mediterranean resulting in a significant portfolio of major development projects. We have a numerous exploration opportunities remaining in these areas and are engaged in new venture activity in other international locations as well.
Appraisal, Development and Exploitation Activities   We assess our exploration successes for potential development as demonstrated in our growing inventory of major projects.  In 2009, we sanctioned the Isabela and Aseng projects and are progressing toward sanctioning the Tamar, Belinda and Gunflint projects during 2010 and/or 2011.We support a significant portion of the capital needs of these major projects with our long-lived inventory of low-risk development and exploitation projects.  Low-risk development and exploitation projects, such as the Wattenberg field in our North America operations, also provide diversification and balance to our worldwide portfolio.
Acquisition and Divestiture Activities     We maintain an ongoing portfolio optimization program. Accordingly, we may engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also divest non-core assets in order to optimize our property portfolio.
Pending Asset Acquisition In January 2010, we announced that we have entered into a definitive agreement to acquire substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for $494 million. We estimate total proved reserves to be 53 MMBoe, 45% of which are liquids and 80% are within the liquid-rich Wattenberg field, where our largest onshore US asset is located. The acquisition will add approximately 10 MBoepd, or 46 MMcf of natural gas and 2.5 MBbls of liquids to our daily production base, starting from the closing date, for 2010 and will provide significant growth potential. Included in the purchase are 340,000 total net acres, nearly 200,000 of which are located in the Greater Denver-Julesberg (DJ) Basin. The acquisition is expected to close late in the first quarter 2010 and is subject to customary closing conditions. See United States - Northern Region discussion below.


Mid-continent Acquisition   In 2008, we acquired producing properties in western Oklahoma for $292 million. Properties acquired cover approximately 15,500 net acres. The total purchase price was allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.
Sale of Argentina Assets   In 2008, we closed on the sale of our producing property interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. The $24 million gain on sale was deferred until 2009 when approval was obtained from the Argentine government. Our crude oil reserves for Argentina totaled 7 MMBbls at December 31, 2007.
Sale of Gulf of Mexico Shelf Properties  In 2006, we sold all of our significant Gulf of Mexico shelf properties except for the Main Pass area, which required repairs related to hurricane damage at the time. As of the effective date of the sale, proved reserves for the Gulf of Mexico properties sold totaled approximately 7 MMBbls of crude oil and 110 Bcf of natural gas. The deepwater Gulf of Mexico remains a core area and is more aligned with our long-term business strategies.
U.S. Exploration Acquisition   In 2006, we acquired U.S. Exploration, a privately held corporation, for $412 million plus liabilities assumed. U.S. Exploration’s reserves and production were located primarily in Colorado’s Wattenberg field. This acquisition significantly expanded our operations in one of our core areas. Proved reserves of U.S. Exploration at the time of acquisition were approximately 234 Bcfe, of which 38% were proved developed and 55% natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were valued at $131 million. In addition, we recorded $34 million of goodwill. 
Patina Merger  In 2005, we acquired Patina through merger (Patina Merger) for a total purchase price of $4.9 billion. Patina’s long-lived crude oil and natural gas reserves provided a significant inventory of low-risk opportunities that balanced our portfolio. Patina’s proved reserves at the time of acquisition were estimated to be approximately 1.6 Tcfe, of which 72% were proved developed and 67% natural gas. Proved crude oil and natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. In addition, we recorded $875 million of goodwill.

United States
We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. The Patina Merger and the acquisition of U.S. Exploration significantly increased the breadth of our onshore operations, especially in the Rocky Mountains and Mid-continent areas. These two acquisitions, along with other acquisitions of producing and non-producing properties, have provided us with a multi-year inventory of exploitation and development opportunities. We expect to close on a purchase of additional US Rocky Mountain assets in first quarter 2010, which will further increase our operations and project inventory in this area. In 2009, we were awarded 22 new leases in the deepwater Gulf of Mexico.
US operations accounted for 56% of our 2009 consolidated sales volumes and 56% of total proved reserves at December 31, 2009. Approximately 55% of the proved reserves are natural gas and 45% are crude oil, condensate and NGLs. Our onshore US portfolio at December 31, 2009 included 956,000 net developed acres and 1.3 million net undeveloped acres. We currently hold interests in 103 offshore blocks in the Gulf of Mexico.
Sales of production and estimates of proved reserves for our significant US operating areas were as follows:
  Year Ended December 31, 2009 December 31, 2009 
  Sales Volumes Proved Reserves 
  Crude Oil & Condensate Natural Gas NGLs Total Crude Oil, Condensate & NGLs Natural Gas Total 
  (MBpd) (MMcfpd) (MBpd) (MBoepd) (MMBbls) (Bcf) (MMBoe) 
Northern Region               
Wattenberg Field  15  150  6  46  129  819  266 
Mid-continent Area  7  66  1  19  34  279  80 
Other  -  95  -  16  1  290  49 
Total  22  311  7  81  164  1,388  395 
Southern Region                      
Deepwater Gulf of Mexico  10  49  3  21  26  47  34 
Other  5  37  -  11  19  98  35 
Total  15  86  3  32  45  145  69 
Total United States  37  397  10  113  209  1,533  464 



4

Wells drilled in 2009 and productive wells at December 31, 2009 for our significant US operating areas were as follows:
  Year Ended December 31, 2009 December 31, 2009 
  Gross Wells Drilled or Participated in Gross Productive Wells 
Northern Region       
Wattenberg Field        424                      6,285 
Mid-Continent Area           31                      3,920 
Other         145                      2,648 
Total        600                     12,853 
Southern Region       
Deepwater Gulf of Mexico             2                              11 
Other          32                        1,180 
Total          34                         1,191 
Total United States        634                     14,044 
Locations of our US onshore operations in the Wattenberg field, Mid-continent area and other significant areas are shown on the map below:

Northern Region The Northern region consists of our operations in the Rocky Mountain area, which includes the DJ (Wattenberg field), Piceance, San Juan, and Wind River basins, as well as the Niobrara (Tri-State) and Bowdoin fields. The Rocky Mountain area is one of our core operating assets. The Northern region also includes the Mid-continent area, consisting of properties in the Texas Panhandle, Oklahoma and Kansas.
Wattenberg Field   The Wattenberg field (approximately 96% operated working interest), located in the DJ basin of north central Colorado, is our largest onshore US field and continues to grow. We acquired working interests in the Wattenberg field through the Patina Merger in 2005 and acquisition of U.S. Exploration in 2006. The Wattenberg field held 57% of our US proved reserves at December 31, 2009.
One of the most attractive features of the field is the presence of multiple productive formations, which include the Codell, Niobrara, and J-Sand formations, as well as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman formations. Drilling in the Wattenberg field is considered lower risk from the perspective of finding crude oil and natural gas reserves.

5

Our current field activities are focused primarily on the improved recovery of reserves through drilling new wells or deepening within existing wellbores, recompleting the Codell formation within existing J-Sand wells, refracturing or trifracturing existing Codell wells and refracturing or recompleting the Niobrara formation within existing Codell wells. A refracture consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. A trifracture is effectively a refracture of a refracture. These projects and continued success with our production enhancement program, which includes well workovers, reactivations, and commingling of zones, allow us to increase production and add proved reserves to what is considered a mature field.
Due to economic conditions, our 2009 program decreased from 2008 levels. In 2009, we drilled or participated in 424 gross Wattenberg field development wells, with a 100% success rate. Three of these wells were horizontal wells targeting the Niobrara formation. We added approximately 36 MMBoe of proved reserves, approximately 49% of which were natural gas.  At year-end, we were running five drilling rigs and 17 completion units in the field.
We have experienced significant growth in production from the Wattenberg field, from an average of 33 MBoepd at year-end 2005 to approximately 45 MBoepd for fourth quarter 2009. Expansion of field boundaries has resulted in a large increase in our crude oil and NGL stream since year-end 2005. As a result, year-end 2009 production included approximately 20 MBpd of liquids. Sales of Wattenberg field production accounted for 41% of total US sales volumes in 2009.
The infrastructure in this area is improving and expanding. Oil transport alternatives improved in 2009 with the start up of a new interstate crude oil transportation pipeline system running from Weld County, Colorado, where the Wattenberg field is located, to Cushing, Oklahoma. The pipeline, in which we own a small equity interest, provides another option for the marketing of our crude oil. We have a five-year throughput agreement with the pipeline.
We continue to acquire acreage in the area and held interests in approximately 350,000 net acres at year-end 2009. We are planning an active capital program in 2010 and expect to increase the program from 2009 levels, drilling approximately 500 wells, with continued focus on new wells in the Codell/Niobrara formations. We will have the flexibility with short-term drilling rig contracts to decrease activity if economic conditions decline. Additionally, we have a substantial project inventory remaining and plan to continue steady refracture, trifracture, and recompletion programs in 2010.
As discussed under Acquisition and Divestiture Activities – Pending Asset Acquisition above, we expect to close on an acquisition of additional US Rocky Mountain assets late in the first quarter 2010. We have identified several thousand projects associated with the assets being acquired, including over 2,000 Codell/Niobrara drilling locations in Wattenberg. We plan to add two rigs to our Wattenberg program in 2010 as a result of the transaction. We expect this activity to grow net production, with a focus on increasing liquids contribution.

Mid-continent Area   The Mid-continent area includes properties in the Texas Panhandle, Oklahoma and Kansas. Significant areas of activity have been in the Cleveland Sandstone area of western Oklahoma (89% operated working interest). We drilled or participated in 31 development wells in 2009, 97% of which were successful.
In 2009, we continued drilling in the Cleveland Sandstone formation in western Oklahoma, on acreage we acquired in 2008. Cleveland Sandstone is a tight gas play characterized by low-permeability rock. We drilled 20 wells (included in the count above) using horizontal drilling techniques, all of which were successful, and recent wells have come on line with greater than 40% liquids production. We currently have one rig operating and expect to drill approximately the same number of wells in 2010 as we drilled in 2009.
Other Northern Region  Other Northern region areas of activity are as follows:
Piceance Basin – The Piceance basin in western Colorado (approximately 89% operated working interest) is a major North America natural gas basin and is characterized by low-porosity rock. The primary productive formation is the Mesaverde Williams Fork formation.  Multiple wells are drilled from individual drilling pads to reduce rig mobilization costs in mountainous terrain and to minimize environmental impact on the surface area.  Well spacing is approximately ten acres per well.
As in the Wattenberg field, Piceance basin drilling time per well has been reduced due to our increased use of improved drilling technology. In the Piceance basin, we are using new fit-for-purpose rigs which include design innovations and technology improvements that capture incremental time savings during all phases of the well drilling process, including moving between wells. Fit-for-purpose rigs can drill multiple wells from one location and are particularly useful in developing hydrocarbon reserves in tight-gas areas such as the Piceance basin.
In 2009, we drilled or participated in 48 development wells and one exploratory well, 100% of which were successful. Successful drilling activity in recent years has led to significant volume growth; production has grown from 2 MMcfepd in 2005 to 54 MMcfepd for fourth quarter 2009.
We have assembled a significant acreage position in the Piceance basin and currently hold interests in approximately 20,000 net acres providing a large inventory of future projects. At this time, we plan to operate a single-rig drilling program in 2010.
Tri-State Area (Niobrara) – Our operations in the Tri-State area (eastern Colorado, extending into Kansas and Nebraska) center primarily around the development of the Niobrara Trend (approximately 96% operated working interest). The Niobrara formation is an important shallow natural gas producer. Since 2006, we have expanded our acreage position to over 580,000 net acres.  We have a substantial future project inventory, including Niobrara infill and exploitation drilling along with gathering system and compressor station additions to develop reserves and deliver new production.  In 2009, we drilled or participated in 64 development wells, 100% of which were successful, and we plan to continue our Niobrara drilling program in 2010.

Wind River Basin –  At Iron Horse in the Wind River Basin (88% operated working interest) located in central Wyoming, we drilled 18 development wells during 2009 with a 94% success rate.  We plan to continue our drilling program here during 2010 and expect to drill approximately 20 new wells.
Bowdoin and San Juan – We are also active in the Bowdoin field (approximately 63% operated working interest), located in north central Montana and the San Juan basin (approximately 82% operated working interest), located in northwestern New Mexico and southwestern Colorado. In 2009, activity was reduced in these areas as we focused most of our capital spending on the core development fields of Wattenberg, Piceance and western Oklahoma. We drilled or participated in a total of 13 development wells in the Bowdoin field and San Juan basin, 100% of which were successful, and one unsuccessful exploratory well.
Southern Region The Southern region includes the deepwater Gulf of Mexico and onshore areas primarily in Texas and Louisiana.
Deepwater Gulf of Mexico   The deepwater Gulf of Mexico is one of our core areas and accounted for 19% of 2009 US sales volumes and 7% of US proved reserves at December 31, 2009. We currently hold leases on 103 deepwater Gulf of Mexico blocks, representing approximately 390,000 net acres. We operate approximately 86% of the leases. Locations of our deepwater Gulf of Mexico developments are shown on the map below:
We continue to expand our deepwater Gulf of Mexico operations primarily through an active exploration program, expansion of our 3-D seismic database, and lease acquisition. Our exploration activities have led to discoveries at Gunflint, a 2008 discovery which is our largest deepwater Gulf of Mexico discovery to date; Isabela; Redrock/Raton; and, most recently, Santa Cruz.
During 2009, we moved forward with development plans for some of our recent discoveries, as discussed below, and continued our exploratory program. We participated in Central Gulf of Mexico Lease Sale 208 and were awarded 22 new deepwater Gulf of Mexico blocks which will complement our growing inventory of exploration opportunities. We currently have an inventory of over 30 identified prospects, with a combination of both large stand-alone prospects as well as a number of smaller, tie-back opportunities.
Our exploration efforts continued during December 2009 as drilling began on two significant test wells at the Deep Blue prospect (Green Canyon Block 723; 33.75% operated working interest) and one at the Double Mountain prospect (Green Canyon Block 556; 30% non-operated working interest).


Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below:
Gunflint (Mississippi Canyon Block 948; 37.5% operated working interest and Mississippi Canyon Block 949; 43.75% operated working interest)   We announced the Gunflint crude oil discovery, our largest deepwater Gulf of Mexico discovery to date, in October 2008. We have acquired additional seismic information and are preparing to drill one or two appraisal wells in 2010. We are the operator of the development.
Galapagos Development Project including Isabela (Mississippi Canyon Block 562, 33% non-operated working interest) and Santa Cruz (Mississippi Canyon Blocks 519/563, 23.25% operated working interest)  During third quarter 2009, we approved the Galapagos development project, which consists of our 2007 discovery, Isabela, and our 2009 discovery on adjacent acreage, Santa Cruz. The phased development plan includes completion of the Isabela and Santa Cruz wells during second and third quarter 2010, and then connecting them to nearby infrastructure via subsea tiebacks.   Initial production is expected in 2011.  During the first half of 2010, we also plan to drill the Santiago exploration well (23.25% operated working interest) which is a separate prospect in the same offshore block as Santa Cruz.  If the Santiago well is successful, it will be completed in 2010, with production expected in 2011.
Redrock/Raton (Mississippi Canyon Blocks 204, 248 and 292; 66.67 % working interest)   Redrock was a 2006 natural gas/condensate discovery and Raton was a 2006 natural gas discovery. The South Raton appraisal well was also drilled in 2006.  In 2007, we successfully sidetracked and completed the Raton discovery well and it was tied back and came on production in late 2008. In 2008, we drilled a successful sidetrack-appraisal well at South Raton and we currently expect it to be tied back to a host facility. Redrock is currently considered a co-development candidate to the completed sidetrack well at South Raton. We are the operator of Redrock/Raton.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% working interest)   Swordfish was a 2001 discovery and began producing in 2005. During 2009, a Swordfish gas well watered out. We sidetracked the well into an oil zone, and production began in January, 2010. The Swordfish project currently includes three producing wells connected to a third-party production facility through subea tiebacks. We are the operator of Swordfish.
Ticonderoga (Green Canyon block 768; 50% working interest)   Ticonderoga is a non-operated 2004 crude oil discovery and began producing in 2006. The project currently includes three producing wells connected to existing infrastructure through subea tiebacks. In September 2008, Ticonderoga was shut-in as a result of hurricane damage to third-party processing and pipeline facilities. It remained shut-in until August 2009 when it was returned to full production.
Onshore East Texas and North Louisiana   This is an emerging area for us. Recent acquisitions have increased our leasehold acreage to approximately 17,000 gross acres. Our 2009 drilling program targeted the Haynesville shale (approximately 60% working interest), and we completed our first horizontal East Texas Haynesville shale well with an initial thirty-day average production rate of over 11 MMcfpd, gross. We drilled a second exploration well in fourth quarter 2009 that was completed in late January 2010 and is being tested. We plan to drill approximately 10 to 11 Haynesville wells on our operated acreage in 2010 and participate in another seven to eight Haynesville wells operated by others.
International
International operations are significant to our business, accounting for 44% of consolidated sales volumes in 2009 and 44% of total proved reserves at December 31, 2009. International proved reserves are approximately 64% natural gas and 36% crude oil. Operations in Equatorial Guinea, Ecuador, China and Suriname are conducted in accordance with the terms of production sharing contracts. In Cameroon, we operate in accordance with the terms of a production sharing contract and a mining concession. Operations in the North Sea, Israel and other foreign locations are conducted in accordance with concession agreements or licenses.


Sales of production and estimates of proved reserves for our significant international operating areas are as follows:
  Year Ended December 31, 2009  December 31, 2009 
  Sales Volumes  Proved Reserves 
  Crude Oil & Condensate  Natural Gas  NGL's  Total  Crude Oil, Condensate & NGLs  Natural Gas  Total 
  (MBpd)  (MMcfpd)  (MBpd)  (MBoepd)  (MMBbls)  (Bcf)  (MMBoe) 
International                     
Equatorial Guinea  14   239   -   54   92   940   248 
Israel  -   114   -   19   -   234   39 
Other  11   31   -   16   35   196   69 
Total International  25   384   -   89   127   1,370   356 
Equity Investee  2   -   6   8   -   -   - 
Total  27   384   6   97   127   1,370   356 
Equity Investee Share of Methanol Sales (MMgal)         145             
Wells drilled in 2009 and productive wells at December 31, 2009 in our international operating areas were as follows:
  Year Ended December 31, 2009 December 31, 2009 
  Gross Wells Drilled or Participated in Gross Productive Wells 
International       
Equatorial Guinea              1                            24 
Israel             3                               5 
North Sea             6                            30 
Ecuador              -                               3 
China              1                             16 
Total International            11                            78 

Locations of our major international operations are shown on the map below:

West Africa (Equatorial Guinea and Cameroon)   West Africa is one of our core operating areas. Crude oil and natural gas sales volumes accounted for 61% of 2009 consolidated international sales volumes and 70% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 53,000 net developed acres and 212,000 net undeveloped acres in Equatorial Guinea and 563,000 net undeveloped acres in Cameroon.


Alba Field   We began investing in West Africa in the early 1990’s. Activities center around our 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, which is one of our most significant assets. Operations include the Alba field and related production and condensate facilities, a methanol plant, and an onshore LPG processing plant (both located on Bioko Island) where additional condensate is produced. The methanol plant is capable of producing up to 3,000 MTpd gross.
We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated LNG plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest accounted for by the equity method. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest accounted for by the equity method. The methanol plant purchases natural gas from the Alba field under a contract that runs through 2026. AMPCO subsequently markets the produced methanol to customers in the US and Europe. Alba Plant sells its LPG products and condensate at our marine terminal at prevailing market prices. We sell our share of condensate produced in the Alba field and from the LPG plant under short-term contracts at market-based prices.
Blocks O and I, YoYo and Tilapia   During the past several years, we have conducted a successful exploration and appraisal drilling program in the Douala basin in West Africa, centering around Blocks O and I, offshore Equatorial Guinea, and the YoYo mining concession and Tilapia production sharing contract offshore Cameroon, where we have an interest in over 1.1 million gross acres. We are the operator in Cameroon (50% working interest) and the technical operator on Block O (45% working interest) and Block I (40% working interest).
Our first discovery occurred in October 2005, when we announced successful test results from the O-1 (Belinda) exploration well offshore Equatorial Guinea. In 2007, we drilled seven wells, resulting in three new discoveries and three successful appraisal wells. In 2008, we announced successful results from the I-5 Benita oil appraisal well on Block I; the Felicita, a condensate and natural gas discovery on Block O; and the Diega, a gas condensate and oil discovery on Block I.  In February 2009, we announced a successful oil discovery on Block O at the Carmen prospect.
In December 2008, we submitted a Plan of Development for the Aseng field (formerly known as Benita) to the government of Equatorial Guinea. On July 22, 2009, we announced that it had been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  
Initial development of the Aseng field will include multiple subsea wells flowing to a floating production, storage and offloading vessel (FPSO) where the production stream will be separated.  The oil will be stored on the FPSO until sold, while the natural gas and water will be reinjected into the reservoir to maintain pressure and maximize oil recoveries. The FPSO is designed with capacity to process 120 MBpd of liquids, including 80 MBpd of oil. In addition, the vessel will be capable of reinjecting 170 MMcfpd of natural gas. Storage on the vessel will be approximately 1.6 MMBbls of liquids. The vessel is designed to act as an oil production hub, and as a liquids storage and offloading hub with capabilities to support future subsea oil field developments, and capabilities to take on board, independently from the production train, stabilized condensate from gas condensate fields in the area. First production from the Aseng field is estimated to commence by mid-year 2012 at 50 MBpd of oil gross (16.5 MBpd net). The FPSO and subsea equipment contracts were awarded in 2009, and construction activities have begun on the FPSO. We have two rigs contracted to assist in field development. Drilling and completion activities have commenced. 
We have evaluated the potential for additional liquids and gas projects, and expect that the next development will be at the Belinda field. We are engaged in geologic and reservoir FEED (front end engineering design) work at Belinda, targeting liquid production from this gas condensate field.  We currently anticipate drilling subsea wells which will be tied to a production facility that would remove liquids and reinject gas for future use pending further development at Belinda.  The liquids would be transported to the FPSO at Aseng for storage and sales.  Belinda project sanction is currently scheduled to occur in 2010 with production beginning in 2013. We are also evaluating future oil projects at Diega and Carmen and currently scheduling first production for 2014.
In 2010, we expect to resume exploration activities offshore Equatorial Guinea and acquire a 3-D seismic survey over YoYo and portions of Tilapia in Cameroon.
Eastern Mediterranean (Israel and Cyprus)   Another core operating area is located offshore Israel. Natural gas sales volumes in Israel accounted for 21% of 2009 consolidated international sales volumes and natural gas reserves accounted for 11% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 29,000 net developed acres and 796,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. Our leasehold position in Israel includes four leases and 17 licenses.  We are the operator of the properties. We also hold a license covering approximately 795,000 net undeveloped acres offshore Cyprus.
Mari-B Field    We have been operating in the Mediterranean Sea, offshore Israel, since 1998, and the Mari-B field (47% working interest) is one of our core international assets. The Mari-B field is the first offshore natural gas production facility in Israel and currently has a peak deliverability of approximately 500 MMcfpd from five wells. In 2008, we commissioned a permanent onshore receiving terminal in Ashdod for distribution of natural gas from the Mari-B field to purchasers. During 2009, we moved forward on a compression project that we expect will recover additional reserves and extend the field’s peak deliverability. We also began mobilizing equipment to drill two development wells planned in the first half of 2010. Together with the completion of the compression work, these new wells will provide substantial, additional near-term gas deliverability and serve as injection wells for natural gas storage in the future.


Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Average sales volumes have risen from 48 MMcfpd in 2004 to a record high of 139 MMcfpd in 2008 and were 114 MMcfpd in 2009. The natural gas market in Israel continues to be robust. The Israel Electric Corporation Limited (IEC), our largest purchaser, has continued to convert power plants to use natural gas as fuel. In 2009, the IEC power plant at Hagit began consuming natural gas purchased from us and in December 2009 we initiated natural gas sales to a new customer, Israel Chemicals Ltd.
During third quarter 2009, we signed a new natural gas sales contract with our primary customer, IEC, under the terms of which they will purchase the majority of our remaining undedicated Mari-B field gas at prices expected to be significantly higher than what we have been receiving under the original contract. The actual price received is tied to a blend of liquids prices and a producer price index.  In addition, it was agreed that all sales from the Mari-B field going forward will be proportionately allocated between the two contracts regardless of the total volume sold.  This is a major change from the past arrangement wherein only “excess” volumes above a threshold level received premium prices. In addition, we have signed a letter of intent (LOI) with IEC, under which IEC expects to purchase natural gas to establish a strategic inventory reserve at Mari-B. The Mari-B partners would provide IEC with injection, storage and withdrawal capabilities for this inventory under a related service agreement.
Competing imports of natural gas from Egypt to Israel began in 2008. However, there is still opportunity for significant new sales in the future as the Israeli infrastructure and markets continue to expand.
Tamar and Dalit   During 2009, our exploratory program resulted in two significant discoveries. In January 2009, we announced a very significant natural gas discovery at the Tamar-1 well at the Tamar prospect (36% working interest), offshore northern Israel, and in February 2009, we announced a successful test of production flow rates at the location. Then in March 2009, we announced another natural gas discovery at the Dalit prospect (36% working interest) followed by a successful well test in April 2009.
We then drilled a Tamar appraisal well (Tamar-2), the results of which increased our estimate of the size of the reservoir and confirmed its high quality and extent. Tamar is the largest discovery in our history.
We are moving forward with Tamar development plans, and expect project sanction and recording of proved reserves in the first half of 2010, with first production projected for 2012.  
In fourth quarter 2009, we signed an LOI to sell natural gas from the Tamar field to Dalia Power Energies (Dalia). Dalia, a privately-owned electricity company, has a license to build a natural gas-fired power plant in Israel with operations planned to commence in 2013. According to terms of the LOI, we and our partners will deliver natural gas volumes of approximately 200 Bcf to Dalia under a 17-year supply agreement. Sales volumes under the LOI may be increased to 700 Bcf depending upon the final size of the power plant and extent of operations. We also signed an LOI to sell natural gas from the Tamar field to IEC. IEC expects to purchase at least 95 Bcf of natural gas per year with the potential to procure significantly higher quantities for a period of 15 years beginning at the startup of Tamar.
We continue to remain focused on the vast exploration potential remaining offshore Israel. The successes at Tamar and Dalit opened up a substantial new natural gas basin, the Levantine.  A 3-D seismic program is underway to collect additional data over several leads on our acreage in the Levantine. Based on results from the seismic program, we are planning to drill an exploratory well in the area in the second half of 2010.
Other
North Sea   We have been conducting business in the North Sea (the Netherlands and the UK) since 1996 and currently have working interests in 18 licenses with working interests ranging from 7% to 40%. We are the operator of one block.  The North Sea accounted for 8% of 2009 consolidated international sales volumes and 7% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 6,000 net developed acres and 44,000 net undeveloped acres.
Most of our production is from the non-operated Dumbarton field (30% working interest) in blocks 15/20a and 15/20b in the UK sector of the North Sea. We also produce from the MacCulloch, Hanze, Cook and other fields.
The Dumbarton development, which began production in 2007, includes a subsea tie-back to the GP III, an FPSO in which we own a 30% interest. Additional development (30% working interest) began in 2008, and two new wells were brought on line.  During 2009, our field optimization work continued.  Dumbarton now has eight horizontal producers and two water injection wells.
The Dumbarton field experienced a controlled shut-down in August 2009, due to a malfunctioning swivel on the FPSO. Production was deferred for essentially all of September and October.
We also participated in the development of the nearby Lochranza discovery in block 15/20a (30% working interest). During 2009, the first Lochranza horizontal well was completed and tied back to Dumbarton’s subsea facilities. Production began in fourth quarter 2009.  We expect a second horizontal well to be completed and come on line in the first quarter of 2010.


We have also participated in the Flyndre project (22.5% working interest) and Selkirk project (30.5% working interest), both located in the UK sector of the North Sea. At Flyndre, we successfully completed an exploratory appraisal well in 2007.  We are currently working with the project operator and other partners to finalize the field development plan and relevant operating agreements. At Selkirk, we participated in the drilling of an appraisal well which was sidetracked to the original discovery well location, to ensure presence of effective reservoir, and suspended as a future producer. We are currently working with our partners on development options.
In 2009, we conducted a market test of our wholly-owned subsidiary Noble Energy (Europe) Limited, which holds our interests in the Netherlands and the UK, and received bids. However, we have not committed to a plan to sell these assets.
Ecuador   Operations in Ecuador accounted for 5% of 2009 consolidated international sales volumes and 8% of international proved reserves at December 31, 2009. The concession covers approximately 12,000 net developed acres and 849,000 net undeveloped acres.
We have been operating in Ecuador since 1996. We utilize natural gas from the Amistad field (in shallow water offshore Ecuador) to generate electricity through a 100%-owned natural gas-fired power plant, located near the city of Machala. The Machala power plant, which began operating in 2002, is a single cycle generator with a capacity of 130 MW from twin turbines. It is the only natural gas-fired commercial power generator in Ecuador and currently one of the lowest cost producers of thermal power in the country. The Machala power plant connects to the Amistad field via a 40-mile pipeline. In 2009, power generation totaled 902 GW hours.
See Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country's unsettled economic and political environment and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Current Conditions in Ecuador.
China     We have been engaged in exploration and development activities in China since 1996, with production beginning in 2003. We have a 57% working interest in the Cheng Dao Xi (CDX) field, which is located in the shallow water of the southern Bohai Bay. During fourth quarter 2009, we drilled one horizontal well from our existing platform at the CDX field and commenced drilling a second well.  The rig will initiate a program to pre-drill a number of production and injection wells designed to be connected to a second platform at the field.  This is part of the ongoing expansion project with plans to install the second platform and connect the additional wells in late 2010. China accounted for 5% of 2009 consolidated international sales volumes and 4% of international proved reserves at December 31, 2009. At December 31, 2009, we held approximately 4,000 net developed acres and no undeveloped acres.
Additional International Locations   We hold approximately four million net undeveloped acres in other international locations including Suriname, Nicaragua, and India.

Proved Reserves Disclosures
Recent SEC Rule-Making Activity   In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:
·
Commodity Prices – Economic producibility of reserves and discounted cash flows are now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
·
Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.
·
Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years, unless the specific circumstances justify a longer time.
·
Reserves Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
·
Reserves Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process.  We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
·
Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.
·
Non-Traditional Resources – The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
We adopted the rules effective December 31, 2009.
Effect of Adoption    Application of the new reserve rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of new 12-month average pricing rules at December 31, 2009 resulted in a decrease in proved reserves of approximately 27 MMBoe. Use of the old year-end prices rules would have resulted in an increase in proved reserves of approximately 34 MMBoe at December 31, 2009. Therefore, the total impact of the new price methodology rules resulted in negative reserves revisions of 61 MMBoe. In addition to the new pricing methodology rules, the new proved undeveloped reserves rules, which limit PUDs to those scheduled to be drilled within the next five years, resulted in an additional reduction of proved reserves of approximately 18 MMBoe.

Internal Controls Over Reserves Estimates  Our policies regarding internal controls over the recording of reserves estimates requires reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Responsibility for compliance in reserves bookings is delegated to our Corporate Reservoir Engineering group and requires that reserves estimates be made by the regional reservoir engineering staff and reviewed by the regional reservoir engineering supervisor.
Qualified petroleum engineers in our Houston, Denver and London offices prepare all reservereserves estimates for our different geographical regions. These reservereserves estimates are reviewed and approved by regional management and senior engineering staff and division management with final approval by the vice president in charge of corporate reservesVice President - Strategic Planning, Environmental Analysis & Reserves (Vice President – Reserves) and certain members of senior management.
Our Vice President – Reserves is the technical person primarily responsible for overseeing the preparation of our reserves estimates. Our Vice President – Reserves has a Bachelor of Science degree in Engineering and over 20 years of industry experience with positions of increasing responsibility in engineering and evaluations. The Vice President – Reserves reports directly to our Chief Executive Officer.
We engage a third-party petroleum consulting firm to audit a significant portion of our reserves.  See Third-Party Reserves Audit below.
Technologies Used in Reserves Estimation   The SEC’s new rules expanded the technologies that a company can use to establish reserves. The SEC now allows use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty.  Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates, including the material additions to the 2009 reserves estimates.
Third-Party Reserves Audit   In each of the years 2009, 2008 2007 and 2006,2007, we retained Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party reservereserves engineers, to perform reservereserves audits of proved reserves. A “reserve audit”, as we use the term, isThe reserves audit for 2009 included a process involving an independent third-party engineering firm’s visits, collectiondetailed review of any20 of our major international, deepwater Gulf of Mexico and all required geologic, geophysical, engineeringUS onshore fields, which covered approximately 78% of US proved reserves and economic data, and such firm’s complete external preparation96% of reserve estimates. Our useinternational proved reserves (86% of the term “reserve audit” is intended only to refer to the collective application of the procedures which NSAI was engaged to perform.total proved reserves). The term “reserve audit” may be defined and used differently by other companies.
The reservereserves audit for 2008 included a detailed review of 18 of our major international, deepwater Gulf of Mexicofields and onshore US fields, which covered approximately 79% of US proved reserves and 97% of international proved reserves (86%86% of total proved reserves).reserves. The reservereserves audit for 2007 included a detailed review of 16 of our major international, deepwater Gulf of Mexicofields and onshore US fields, which covered approximately 71% of US proved reserves and 96% of international proved reserves (81%81% of total proved reserves). The reserve audit for 2006 included a detailed review of 14 of our major international, deepwater Gulf of Mexico and onshore US fields, which covered approximately 80% of our total proved reserves.
 
In connection with the 2008 reserve2009 reserves audit, NSAI prepared its own estimates of our proved reserves. In order to prepare its estimates of proved reserves, NSAI examined our estimates with respect to reservereserves quantities, future producing rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reservereserves categorization, using the definitions for proved reserves set forth in the recently updated Regulation S-X Rule 4-10(a) and subsequent Securities and Exchange Commission (SEC)SEC staff interpretations and guidance. In the conduct of the reservereserves audit, NSAI did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of NSAI which brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. NSAI determined that our estimates of reserves conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(2) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2008,2009, based upon its evaluation. The NSAI opinion concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with generally accepted petroleum engineering and evaluation principles. NSAI’s report is attached as Exhibit 99.2 to this Annual Report on Form 10-K.
 
The fields audited by NSAI are chosen in accordance with company guidelines and result in the audit of a minimum of 80% of our total proved reserves. The fields are chosen by senior engineering staff and division management with approval by the vice president in charge of corporate reserves and certain members of senior management,Vice President – Reserves and are reviewed by senior management and the Board of Directors.
When compared on a field-by-field basis, some of our estimates are greater and some are less than the estimates of NSAI. Given the inherent uncertainties and judgments that go into estimating proved reserves, differences between internal and external estimates are to be expected. On a quantity basis, the NSAI field estimates ranged from twoone MMBoe above to 1416 MMBoe below as compared with our estimates. On a percentage basis, the NSAI field estimates ranged from 10%9% above our estimates to 14%20% below our estimates. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. AtReserves differences at December 31, 2008, reserves differences,2009 were, in the aggregate, were less than 29approximately 21 MMBoe, or 4%3%.


Proved Undeveloped Reserves (PUDs)   As of December 31, 2009, our PUDs totaled 142 MMBbls of crude oil and 769 Bcf of natural gas, for a total of 270 MMBoe.
 
PUD Locations     Approximately 70% of our PUDs at year-end 2009 were associated with our major development areas in the Wattenberg field (onshore US) and the Alba field (offshore Equatorial Guinea). An additional 17% of PUDs at year-end 2009 were associated with major development projects at the Aseng field (offshore Equatorial Guinea) and the Galapagos project (deepwater Gulf of Mexico). All of these projects will have PUDs convert from undeveloped to developed as these projects begin production and/or production facilities are expanded or upgraded.
Changes in PUDS    Changes in PUDs that occurred during the year were due to:
·conversion of approximately 23 MMBoe PUDs into proved developed reserves;
·reclassification of approximately 18 MMBoe PUDs that were not scheduled to be developed within five years from proved to probable reserves; and
·negative revisions of approximately 23 MMBoe in PUDs due to changes in commodity prices.
The majority of the reserves reclassified from proved reserves to probable reserves were associated with the Wattenberg field, where we maintain an extensive multi-year development program.
Development Costs    Costs incurred relating to the development of PUDs were approximately $440 million in 2009, $528 million in 2008 and $390 million in 2007.
Estimated future development costs relating to the development of PUDs are projected to be approximately $900 million in 2010, $800 million in 2011, and $500 million in 2012.
Drilling Plans      All PUD drilling locations are scheduled to be drilled prior to the end of 2014.  PUDs associated with projects other than drilling (such as compression projects) are also expected to be converted to proved developed reserves prior to the end of 2014.  Initial production from these PUDs is expected to begin between 2010 to 2015.
We have 7 MMBoe of PUDs associated with an international discovery that has been booked for longer than five years.  Development planning is proceeding on this project, and drilling is expected to begin in the next two years.  The only other PUDs that have been booked for longer than five years are associated with compression projects.  In those cases, the reserves are expected to be recovered from existing wells.
For more information see the following:
·Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Proved Reserves for a discussion of changes in proved reserves;
·Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves for further discussion of our reserves estimation process;
·Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited) for additional information regarding estimates of crude oil and natural gas reserves, including estimates of proved, proved developed, and proved undeveloped reserves, the standardized measure of discounted future net cash flows, and the changes in the standardized measure of discounted future net cash flows.
Other Reserves Information    Since January 1, 2008,2009, no crude oil or natural gas reservereserves information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (EIA) of the US Department of Energy. We file Form 23, including reservereserves and other information, with the EIA.

 
Recent SEC Rule-Making Activity – In December 2008, the SEC announced that it had approved revisions to modernize its oil and gas company reporting requirements. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information.


Acquisition and Divestiture Activities
We maintain an ongoing portfolio optimization program. Accordingly, we may engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also divest non-core assets in order to optimize our property portfolio.
Mid-continent Acquisition – In July 2008, we acquired producing properties in western Oklahoma for $292 million in cash. Properties acquired cover approximately 15,500 net acres and are currently producing a net 20 MMcfepd. The total purchase price has been preliminarily allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.
Sale of Argentina Assets – In February 2008, we closed on the sale of our interest in Argentina for a sales price of $117.5 million, effective July 1, 2007. The gain on sale has been deferred as the sale is contingent upon approval of the Argentine government. Our crude oil reserves for Argentina totaled 7 MMBbls at December 31, 2007.
Sale of Gulf of Mexico Shelf Properties – In 2006, we sold all of our significant Gulf of Mexico shelf properties except for the Main Pass area, which required repairs related to hurricane damage at the time. As of the effective date of the sale, proved reserves for the Gulf of Mexico properties sold totaled approximately 7 MMBbls of crude oil and 110 Bcf of natural gas. Deepwater Gulf of Mexico and Gulf Coast onshore areas remain core areas and are more aligned with our long-term business strategies. See Item 8. Financial Statements and Supplementary Data—Note 4—Acquisitions and Divestitures.
U.S. Exploration Acquisition – In 2006, we acquired U.S. Exploration, a privately held corporation, for $412 million in cash plus liabilities assumed. U.S. Exploration’s reserves and production are located primarily in Colorado’s Wattenberg field. This acquisition significantly expanded our operations in one of our core areas. Proved reserves of U.S. Exploration at the time of acquisition were approximately 234 Bcfe, of which 38% were proved developed and 55% natural gas. Proved crude oil and natural gas properties were valued at $413 million and unproved properties were valued at $131 million. In addition, we recorded $34 million of goodwill. See Item 8. Financial Statements and Supplementary Data—Note 4—Acquisitions and Divestitures.
Patina Merger – In 2005, we acquired Patina through merger (Patina Merger) for a total purchase price of $4.9 billion. Patina’s long-lived crude oil and natural gas reserves provide a significant inventory of low-risk opportunities that balanced our portfolio. Patina’s proved reserves at the time of acquisition were estimated to be approximately 1.6 Tcfe, of which 72% were proved developed and 67% natural gas. Proved crude oil and natural gas properties were valued at $2.6 billion and unproved properties were valued at $1.1 billion. In addition, we recorded $875 million of goodwill.
Crude Oil and Natural Gas Properties and Activities
We search for crude oil and natural gas properties, seek to acquire exploration rights in areas of interest and conduct exploratory activities. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate, on properties for which we have acquired exploration rights. Our properties consist primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. We also own natural gas processing plants and natural gas gathering and other crude oil and natural gas related pipeline systems which are primarily used in the processing and transportation of our crude oil, natural gas and NGL production.
2009 Budget
Due to the uncertain economic and commodity price environment, we have designed a flexible capital spending program that will be responsive to conditions that develop during 2009. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – 2009 Outlook – 2009 Budget.
United States
We have been engaged in crude oil and natural gas exploration, exploitation and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. The Patina Merger and the acquisition of U.S. Exploration significantly increased the breadth of our onshore operations, especially in the Rocky Mountains and Mid-continent areas. These two acquisitions, along with other acquisitions of producing and non-producing properties, have provided us with a multi-year inventory of exploitation and development opportunities. In 2008, we continued to expand our undeveloped acreage position with the leasing of approximately 502,000 net acres in Colorado, Kansas, Montana, Wyoming, East Texas and Oklahoma, along with 15 new leases in the deepwater Gulf of Mexico.
US operations accounted for 56% of our 2008 consolidated sales volumes and 59% of total proved reserves at December 31, 2008. Approximately 61% of the proved reserves are natural gas and 39% are crude oil, condensate and NGLs. Our onshore US portfolio at December 31, 2008 included 996,000 net developed acres and 1.3 million net undeveloped acres. We currently hold interests in 93 offshore blocks in the Gulf of Mexico.


Sales of production and estimates of proved reserves for our significant US operating areas were as follows:
  
Year Ended December 31, 2008
  
December 31, 2008
 
  
Sales Volumes
  
Proved Reserves
 
  
Crude Oil
 
Natural Gas
 
NGLs
 
Total
  
Crude Oil (1)
 
Natural Gas
 
Total
 
  
(MBopd)
 
(MMcfpd)
 
(MBpd)
 
(MBoepd)
  
(MMBbls)
 
(Bcf)
 
(MMBoe)
 
Northern Region
                
Wattenberg field
 15 146 5 45  118 842 259 
Piceance basin
 - 39 - 7  - 263 44 
Niobrara field (Tri-state area)
 - 26 - 4  - 109 18 
Mid-continent area
 7 72 1 20  37 336 93 
Other
 - 25 - 4  1 122 21 
Total
 22 308 6 80  156 1,672 435 
Southern Region
                
Deepwater Gulf of Mexico
 13 49 3 24  19 64 29 
Gulf Coast onshore and other
 5 38 - 12  23 123 44 
Total
 18 87 3 36  42 187 73 
Total United States
 40 395 9 116  198 1,859 508 
(1)
Includes NGLs.
Wells drilled in 2008 and productive wells at December 31, 2008 for our significant US operating areas were as follows:
  
Year Ended
  
  
December 31, 2008
 
December 31, 2008
  
Gross Wells Drilled/
 
Gross
  
Participated in
 
Productive Wells
Northern Region
    
Wattenberg field
 
          558
 
                       5,731
Piceance basin
 
          125
 
                          238
Niobrara field (Tri-State area)
 
          243
 
                          982
Mid-continent area
 
            93
 
                       4,178
Other
 
            31
 
                       1,273
Total
 
       1,050
 
                     12,402
Southern Region
    
Deepwater Gulf of Mexico
 
              3
 
                            12
Gulf Coast onshore and other
 
            70
 
                       1,073
Total
 
            73
 
                       1,085
Total United States
 
       1,123
 
                     13,487



Northern Region—The Northern region consists of our operations in the Rocky Mountains area, which includes the Denver-Julesburg (D-J) (Wattenberg field), Piceance, San Juan, and Wind River basins, as well as the Niobrara (Tri-State), Bowdoin and Siberia Ridge fields. The Northern region also includes the Mid-continent area, consisting of properties in the Texas Panhandle, Oklahoma and Kansas. The Rocky Mountains area is one of our core operating assets. During 2008, we acquired a total of approximately 490,000 net acres in southern Montana, the Mid-continent area and the Niobrara and Wattenberg fields.
Wattenberg Field—The Wattenberg field (approximately 96% operated working interest), located in the D-J basin of north central Colorado, is our largest onshore US field and continues to grow. We acquired working interests in the Wattenberg field through the Patina Merger in 2005 and acquisition of U.S. Exploration in 2006. The Wattenberg field held 51% of our US proved reserves on December 31, 2008.
One of the most attractive features of the field is the presence of multiple productive formations, which include the Codell, Niobrara, and J-Sand formations, as well as the D-Sand, Dakota and the shallower Shannon, Sussex and Parkman formations. Drilling in the Wattenberg field is considered lower risk from the perspective of finding crude oil and natural gas reserves.
Our current field activities are focused primarily on the improved recovery of reserves through drilling new wells or deepening within existing wellbores, recompleting the Codell formation within existing J-Sand wells, refracturing or trifracturing existing Codell wells and refracturing or recompleting the Niobrara formation within existing Codell wells. A refracture consists of the restimulation of a producing formation within an existing wellbore to enhance production and add incremental reserves. A trifracture is effectively a refracture of a refracture. These projects and continued success with our production enhancement program, which includes well workovers, reactivations, and commingling of zones, allow us to increase production and add proved reserves to what is considered a mature field.


We continue to improve efficiencies in Wattenberg field drilling and completion operations and have significantly reduced drilling time by utilizing the latest available technology, including automatic drilling rigs (ADRs). An ADR uses an automated system to regulate the drill string of a drilling rig in response to current drilling conditions, including drilling fluid pressure, bit weight, drill string torque, and drill string revolutions per minute to achieve an optimal rate of bit penetration.
In 2008, we drilled or participated in 558 Wattenberg field development wells, with a 99.8% success rate and added approximately 186 Bcfe of proved reserves approximately 59% of which were natural gas.  At year-end, we were running six drilling rigs and 15 completion units in the field.
We have experienced significant growth in production from the Wattenberg field, from an average of 199 MMcfepd at year-end 2005 to approximately 268 MMcfepd at year-end 2008. Approximately 54% of 2008 production was natural gas. However, expansion of field boundaries has resulted in a 110% increase in our crude oil and NGL stream since year-end 2005. In 2008, sales of Wattenberg field production accounted for 39% of total US sales volumes.
The infrastructure in this area is improving and expanding. Oil transport alternatives should improve in 2009 with the expected start up of a new interstate crude oil transportation pipeline system which will run from Weld County, Colorado, where the Wattenberg field is located, to Cushing, Oklahoma. The pipeline, in which we own a small equity interest, will provide another option for the marketing of our crude oil. We have entered into a five-year throughput agreement with the pipeline.
We continue to acquire acreage in the area and held interests in approximately 332,000 net acres at year-end 2008. We are planning an active capital program in 2009; however, our program may decrease from 2008 levels.  We will have the flexibility with short-term drilling rig contracts to decrease activity if economic conditions continue to decline. We will continue to have a strong focus on Codell/Niobrara new drills.  Additionally, we have a substantial project inventory remaining and plan to continue steady refracture, trifracture, and recompletion programs in 2009.
Piceance Basin—The Piceance basin in western Colorado (approximately 93% operated working interest) is another core area for us. It is a major North American natural gas basin, characterized by low-porosity rock. The primary productive formation is the Mesaverde Williams Fork formation.  Multiple wells are drilled from individual drilling pads to reduce rig mobilization costs in mountainous terrain and to minimize environmental impact on the surface area.  Well spacing is approximately ten acres per well.
As in the Wattenberg field, Piceance basin drilling time per well has been reduced significantly due to our increased use of improved drilling technology. In the Piceance basin, we are using new fit-for-purpose rigs which include design innovations and technology improvements that capture incremental time savings during all phases of the well drilling process, including moving between wells. Fit-for-purpose rigs can drill multiple wells from one location and are particularly useful in developing hydrocarbon resources in tight-gas areas such as the Piceance basin.
In 2008, we increased our drilling activities and drilled or participated in 124 development wells and one exploratory well, 100% of which were successful. Our 2008 drilling activity resulted in the addition of 135 Bcfe of proved reserves. Successful drilling activity in recent years has led to significant volume growth; production has grown from 2 MMcfepd in 2005 to 53 MMcfepd at year-end 2008.
We have assembled a significant acreage position in the area and currently hold interests in approximately 19,000 net acres providing a large inventory of future projects. At this time, we plan to operate a two-rig drilling program in 2009.
Tri-State Area (Niobrara)—Our operations in the Tri-State area (eastern Colorado, extending into Kansas and Nebraska) center primarily around the development of the Niobrara Trend (approximately 88% operated working interest). The Niobrara formation is an important shallow gas producer. Since 2006, we have expanded our acreage position to over 580,000 net acres.  We have a substantial future project inventory, including Niobrara infill and exploitation drilling along with gathering system and compressor station additions to develop reserves and deliver new production in 2009.  We are planning an active capital program in 2009; however, our program may decrease from 2008 levels.  We will have the flexibility with short-term drilling rig contracts to decrease activity if economic conditions continue to decline.
In 2008, we doubled our drilling activity and drilled or participated in 243 development wells. Increased use of 3-D seismic to optimize well locations helped increase our success rate to over 80% in 2008. Our 2008 drilling activity resulted in the addition of 35 Bcfe of proved reserves, and we were producing approximately 28 MMcfepd, net at year-end.  Short-term drilling rig contracts allow flexibility for our drilling plans if economic conditions continue to decline.


Mid-continent Area—The Mid-continent area includes properties in the Texas Panhandle, Oklahoma and Kansas. Significant areas of activity have been the Granite Wash development in the Texas Panhandle, infill drilling in several of our Oklahoma waterfloods, and deeper completions to the Skinner formation in western Oklahoma. We drilled or participated in 92 development wells in 2008, 96% of which were successful and one successful exploratory well. The potential for Granite Wash horizontal drilling is currently being evaluated, which, if successful, could increase the recovery of reserves in place and daily production rates.
In July 2008, we expanded into a new area with a 15,500 net acre acquisition in western Oklahoma, which included approximately 16 MMboe of proved reserves. The target area is the Cleveland Sandstone, a tight gas play characterized by low-permeability rock. Since acquiring the property we have drilled seven development wells (included in the well count above). There are currently 56 operated wells on the property producing in aggregate a net 20 MMcfepd.  We have the flexibility of operating one to three rigs in 2009 with two rigs currently operating.
Other—We are also active in the Bowdoin field (approximately 63% operated working interest), located in north central Montana; the San Juan basin (approximately 82% operated working interest), located in northwestern New Mexico and southwestern Colorado; and the Wind River basin (approximately 74% operated working interest), located in central Wyoming. In 2008, we drilled or participated in a total of 31 development wells in these areas, 100% of which were successful. We plan to have reduced activity in these areas in 2009 as we focus most of our capital spending on the core development fields of Wattenberg, Piceance and Tri-State.
During 2008, we acquired approximately 205,000 net exploratory acres in southern Montana and plan to test the area in 2009.
Southern Region—The Southern region includes the deepwater Gulf of Mexico and onshore areas primarily in Texas, Louisiana, Illinois and Indiana. In 2006, we sold all of our significant Gulf of Mexico shelf properties except for the Main Pass area, which is currently held for sale. The sale of our shelf properties allowed us to migrate future investments and growth from the Gulf of Mexico shelf to the deepwater Gulf of Mexico which we believe is an area of higher potential.
Deepwater Gulf of Mexico—The deepwater Gulf of Mexico is one of our core areas and accounted for 21% of 2008 US sales volumes and 6% of US proved reserves at December 31, 2008. We currently hold interests in 93 deepwater Gulf of Mexico leases, representing approximately 315,000 net acres. We operate approximately 70% of the leases.


The expansion of our deepwater Gulf of Mexico program began in 2004 with the Ticonderoga discovery and the acquisition of additional ownership interests in Swordfish and Lorien. Since then we have continued to expand our operations primarily through an active exploration program, expansion of our 3-D seismic database, and lease acquisition. Our exploration activities have led to significant discoveries at Isabela and Redrock/Raton, and, most recently, Gunflint, a 2008 discovery which is our largest deepwater Gulf of Mexico discovery to date. Participation in the 2008 central Gulf of Mexico outer continental shelf sale resulted in our being awarded 15 new deepwater Gulf of Mexico leases for approximately $167 million, net to our interest, and allows us to expand our inventory with the addition of several new deepwater Gulf of Mexico prospects in the Atwater Valley, Mississippi Canyon, Green Canyon, Walker Ridge, and Garden Banks areas.


In addition to Gunflint, 2008 exploration drilling activities included a well at the Noble-operated Tortuga prospect (Mississippi Canyon Blocks 561 and 605; 57% working interest). Although the well was successful in locating hydrocarbons, we decided not to develop the prospect due to near-term lease expiration as well as other considerations. Accordingly, we impaired the well in the fourth quarter of 2008. We also announced that an exploration well at the Stones River prospect (Mississippi Canyon Block 285; 100% working interest) did not encounter hydrocarbons in commercial quantities.
We plan to continue exploration activities in 2009 by conducting a seismic program and drilling two to three exploratory wells.
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below:
Gunflint (Mississippi Canyon Block 948; 37.5% working interest) – We originally acquired the block in the 2006 central Gulf of Mexico outer continental shelf sale and announced the Gunflint crude oil discovery, our largest deepwater Gulf of Mexico discovery to date, in October 2008. We are currently acquiring additional seismic information and preparing to drill an appraisal well in 2009 or early 2010. We are the operator of the block.
Isabela (Mississippi Canyon Block 562, 33% working interest) – Isabela was a 2007 discovery and is non-operated. Development planning is underway, Phase 1 of which is anticipated to include a producing well with a subsea tieback to an existing production facility. Initial production is currently anticipated in 2011. We also have an interest in adjacent acreage with additional exploration potential on Mississippi Canyon Blocks 519 and 563 (23.25% working interest).  We are currently drilling an exploratory well on Block 519 (Santa Cruz prospect).
Redrock/Raton (Mississippi Canyon Blocks 204, 248 and 292; 66.67 % working interest) – Redrock was a 2006 natural gas/condensate discovery and Raton was a 2006 natural gas discovery. The Raton South appraisal well was also drilled during 2006.  In 2007, we successfully sidetracked and completed the Raton discovery well and it was tied back and came on production in late 2008. In 2008, we drilled a successful sidetrack-appraisal well at Raton South, and tie back to a host facility is anticipated in late 2009. Redrock is currently considered a co-development candidate to the completed sidetrack well at Raton South. We are the operator of Redrock/Raton.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% working interest) – Swordfish was a 2001 discovery and began producing in 2005. In 2007, we drilled and completed a sidetrack to Viosca Knoll Block 917 #1 well, which began production at the end of 2007. The Swordfish project currently includes three producing wells connected to a third-party production facility through subea tiebacks. We are the operator of Swordfish.
Ticonderoga (Green Canyon block 768; 50% working interest) – Ticonderoga is a non-operated 2004 crude oil discovery and began producing in 2006. In 2007, we drilled and completed the #3 and #1 ST4 wells to extend and enhance production from the field.  The wells came on line first quarter 2008. The project currently includes three producing wells connected to existing infrastructure through subea tiebacks.
Lorien (Green Canyon Block 199; 60% working interest) – Lorien was a 2003 crude oil discovery and began producing in 2006.  The project currently includes two producing wells connected to existing infrastructure through subea tiebacks. We are the operator of Lorien.
In September 2008, Hurricanes Gustav and Ike moved through the Gulf of Mexico. Inspection of our facilities and equipment indicated there was no major damage from the hurricanes, although damage to third party processing and pipeline facilities has slowed reinstatement of production from our Gulf of Mexico assets, including Lorien and Ticonderoga. Approximately 8.5 MBoepd of production remained shut-in at year-end. We expect production to resume during the first half of 2009, depending on the successful resumption of pipeline and other non-operated facilities.
New Albany Shale—We continue to selectively increase our acreage position in resource plays, including shale plays. We have accumulated over 179,000 net acres in the New Albany Shale in the Illinois Basin (approximately 92% working interest), located in Indiana and Illinois. During 2008, we drilled 11 development wells, 100% of which were successful. We also drilled 12 development wells in the Paxton area, 92% of which were successful, and seven successful exploration wells on our Round Rock acreage in the Illinois Basin.


East Texas and North Louisiana—This is an emerging area for us. Recent acquisitions have increased our leasehold acreage to approximately 17,700 net acres. In 2008, we drilled seven horizontal James Lime wells and 24 Hosston, Travis Peak and Cotton Valley wells, all of which were successful. We also participated in the drilling of one successful horizontal Haynesville shale well in North Louisiana.  Our drilling program for 2009 will focus on the Haynesville shale.
Other— In addition to the East Texas and North Louisiana programs, we drilled six successful development wells within the South Central Robertson Unit in west Texas and two Gulf Coast exploratory wells.
International
International operations are significant to our business, accounting for 44% of consolidated sales volumes in 2008 and 41% of total proved reserves at December 31, 2008. International proved reserves are approximately 68% natural gas and 32% crude oil. Operations in Equatorial Guinea, Cameroon, Ecuador, China and Suriname are conducted in accordance with the terms of production sharing contracts. Operations in other foreign locations are conducted in accordance with concession agreements or licenses.
Sales of production and estimates of proved reserves for our significant international operating areas are as follows:
  
Year Ended December 31, 2008
  
December 31, 2008
 
  
Sales Volumes
  
Proved Reserves
 
  
Crude Oil
 
Natural Gas
 
NGL's
 
Total
  
Crude Oil
 
Natural Gas
 
Total
 
  
(MBopd)
 
(MMcfpd)
 
(MBpd)
 
(MBoepd)
  
(MMBbls)
 
(Bcf)
 
(MMBoe)
 
International
                
West Africa
 15 206 - 49  75 978 238 
North Sea
 10 5 - 11  23 19 27 
Israel
 - 139 - 23  - 273 46 
Ecuador
 - 22 - 4  - 180 30 
China
 4 - - 4  15 6 15 
Total consolidated
 29 372 - 91  113 1,456 356 
Equity investee
 2 - 6 8        
Total
 31 372 6 99  113 1,456 356 
Equity investee share of methanol sales (MMgal)
       119        

Wells drilled in 2008 and productive wells at December 31, 2008 in our international operating areas were as follows:
  
Year Ended
    
  
December 31, 2008
  
December 31, 2008
 
  
Gross Wells
  
Gross
 
  
Drilled/Participated in
  
Productive Wells
 
International
      
West Africa
  3   23 
North Sea
  4   26 
Israel
  -   6 
Ecuador
  -   5 
China
  -   15 
Suriname
  1   - 
Total International
  8   75 
West Africa (Equatorial Guinea and Cameroon)—Operations in West Africa accounted for 54% of 2008 consolidated international sales volumes and 67% of international proved reserves at December 31, 2008. At December 31, 2008, we held approximately 15,000 net developed acres and 250,000 net undeveloped acres in Equatorial Guinea and 563,000 net undeveloped acres in Cameroon.  In 2008, approximately 190,000 gross undeveloped acres were relinquished in Equatorial Guinea pursuant to contract terms.
We began investing in West Africa in the early 1990’s. Activities center around our 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, which is one of our most significant assets. Operations include the Alba field and related production and condensate facilities, a methanol plant, and an onshore LPG processing plant (both located on Bioko Island) where additional condensate is produced. The methanol plant is capable of producing up to 3,000 MTpd gross.
We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant and an unaffiliated LNG plant. The LPG plant is owned by Alba Plant LLC (Alba Plant) in which we have a 28% interest accounted for by the equity method. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO) in which we have a 45% interest accounted for by the equity method. The methanol plant purchases natural gas from the Alba field under a contract that runs through 2026. AMPCO subsequently markets the produced methanol to customers in the US and Europe. We sell our share of condensate produced in the Alba field and from the LPG plant under short-term contracts at market-based prices.
West Africa Exploration Activities — We have conducted a successful exploration and appraisal drilling program in West Africa, which centers around Blocks O and I, offshore Equatorial Guinea, and the PH-77 license, offshore Cameroon. We are the technical operator on Block O (45% working interest) and Block I (40% working interest) and the operator on the PH-77 license (50% working interest).

Our first discovery occurred in October 2005, when we announced successful test results from the O-1 (Belinda) exploration well offshore Equatorial Guinea. In 2007, we drilled seven wells, resulting in three new discoveries and three successful appraisal wells. In 2008, we announced successful results from the I-5 Benita oil appraisal well on Block I; the Felicita, a condensate and natural gas discovery on Block O; and the Diega, a gas condensate and oil discovery on Block I.  In February 2009, we announced a successful oil discovery on Block O at the Carmen prospect.
We are in the process of assessing our options to commercialize our discoveries in the region. Engineering studies are underway, and we expect to utilize a phased-in approach for development.  A development plan for the Benita discovery on Block I was submitted to the Equatorial Guinean government in December 2008, and we await their approval. We anticipate sanction of the Benita project to occur in 2009, with first oil production planned for 2012. The Benita development is expected to include subsea tie-backs to a floating production, storage and offloading vessel (FPSO). We are also evaluating options for natural gas production and marketing.
North Sea—Operations in the North Sea (the Netherlands and the UK) comprise another core international asset. We have been conducting business in the North Sea since 1996 and currently have working interests in 18 licenses with working interests ranging from 7% to 40%. We are the operator of one block.  The North Sea accounted for 13% of 2008 consolidated international sales volumes and 8% of international proved reserves at December 31, 2008. During 2008, we relinquished approximately 159,000 gross undeveloped acres. At December 31, 2008, we held approximately 6,000 net developed acres and 54,000 net undeveloped acres.
We produce from the Dumbarton, MacCulloch, Hanze, Cook and other fields. Most of our production is from the non-operated Dumbarton Phase I development (30% working interest) in blocks 15/20a and 15/20b in the UK sector of the North Sea. The Dumbarton development, which was completed and began production in 2007, includes a subsea tie-back to the GP III, an FPSO in which we own a 30% interest.
In 2008, we continued the development of Dumbarton (30% working interest) with Phase 2. Phase 2 involves drilling up to six new horizontal production wells and up to two water disposal wells. The first two wells in Phase 2 were brought online in 2008, increasing the total field production to approximately 40,000 Bopd, gross. With the additional two wells, Dumbarton now has seven horizontal producers and two water injection wells. Phase 2 drilling will continue into 2009.  As part of the project we plan to participate in the development of the Lochranza discovery in block 15/20a (30% working interest) which includes drilling two horizontal production wells which will be tied back to the Dumbarton subsea facilities.
During 2008, we also participated in drilling the Morgan exploratory well, in the UK Central North Sea (40% working interest). The well did not contain hydrocarbons in commercial quantities.
Israel—Operations in Israel accounted for 25% of 2008 consolidated international sales volumes and 13% of international proved reserves at December 31, 2008. At December 31, 2008, we held approximately 29,000 net developed acres and 807,000 net undeveloped acres located between 10 and 60 miles offshore Israel in water depths ranging from 700 feet to 5,500 feet. Our leasehold position in Israel includes one preliminary permit, two leases and three licenses.  We are the operator of our Israel properties.
We have been operating in the Mediterranean Sea, offshore Israel, since 1998, and the Mari-B field (47% working interest) is one of our core international assets. The Mari-B field is the first offshore natural gas production facility in Israel and has peak field deliverability of approximately 600 MMcfpd from six wells. In 2008, we commissioned a permanent onshore receiving terminal in Ashdod for distribution of natural gas from the Mari-B field to purchasers.
Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Average sales volumes have risen from 48 MMcfpd in 2004 to 139 MMcfpd in 2008. The Israel Electric Corporation Limited (IEC) is our largest purchaser. The IEC has continued to convert power plants to use natural gas as fuel and, in 2008, the IEC power plant at Gezer began purchasing natural gas from us.  We also sell to the Bazan Oil Refinery, Delek Independent Power Production and associated desalinization plant, and a paper mill. In 2008, we entered a new five-year natural gas sales contract with Israel Chemicals Ltd, with sales expected to begin in 2009. In addition, the IEC power plant at Hagit is expected to begin purchasing natural gas from us in 2009. Imports of natural gas from Egypt to Israel began in 2008. However, there is still potential for significant new sales in the future as the Israeli infrastructure and markets continue to expand.
We are continuing exploration activities in Israel. In fourth quarter 2008, we began drilling an exploration well to test the Tamar prospect (36% working interest), offshore northern Israel, and in January 2009, we announced a very significant natural gas discovery at Tamar.  In February 2009, we announced a successful test of production flow rates at Tamar as well as our plans to drill an appraisal well later in the year.  We have conducted additional seismic activities in the area and are conducting a compression study at the Mari-B field.

Other International—Other international at December 31, 2008 includes the following:
Ecuador—Operations in Ecuador accounted for 4% of 2008 consolidated international sales volumes and 8% of international proved reserves at December 31, 2008. The concession covers approximately 12,000 net developed acres and 852,000 net undeveloped acres.
We have been operating in Ecuador since 1996. We utilize natural gas from the Amistad field (offshore Ecuador) to generate electricity through a 100%-owned natural gas-fired power plant, located near the city of Machala. The Machala power plant, which began operating in 2002, is a single cycle generator with a capacity of 130 MW from twin turbines. It is the only natural gas-fired commercial power generator in Ecuador and currently one of the lowest cost producers of thermal power in the country. The Machala power plant connects to the Amistad field via a 40-mile pipeline. In 2008, power generation totaled 749 GW hours.
China — We have been engaged in exploration and development activities in China since 1996 with production beginning in 2003. We are operator for the joint operating group of the Cheng Dao Xi field (57% working interest), which is located in the shallow water of the southern Bohai Bay. In 2008, activities consisted primarily of workover operations, including installations of electric submersible pumps. China accounted for 4% of 2008 consolidated international sales volumes and 4% of international proved reserves at December 31, 2008. At December 31, 2008, we held approximately 4,000 net developed acres and no undeveloped acres. The Supplemental Development Plan, which is designed to further develop the Cheng Dao Xi field through additional drilling and facilities construction, has received all necessary governmental approvals.
Suriname — Suriname, a country located on the northern coast of South America, represents a new exploration area for us. We have entered into participation agreements on non-operated Block 30 (45% working interest) and on Block 32 (100% working interest), which combined cover approximately 6.4 million net acres offshore. During 2008, we participated in the drilling of an exploratory well on the West Tapir prospect on Block 30. The well, which did not contain hydrocarbons in commercial quantities, was the first well to be drilled offshore Suriname in over 20 years and the drilling results will allow us to evaluate and improve our understanding of the basin. We will incorporate the findings into our geological and geophysical interpretations, which will influence our risk assessment of the remaining prospects.























Sales Volumes, Price and Cost Data—Data Sales volumes, price and cost data are as follows:
 
  Sales Volumes Average Sales Price 
Production 
Cost (1)
 
  Crude Oil MBpd Natural Gas MMcfpd NGLs MBpd Crude Oil Per Bbl Natural Gas Per McfNGLs Per Bbl Per BOE 
Year Ended December 31, 2009               
United States               
Wattenberg Field  15  150  6 $55.57 $3.59 $29.10 $3.01 
Other US  22  247  4  54.92  3.62  26.37  8.50 
Total US (2)
  37  397  10  55.19  3.61  27.96  6.26 
Alba Field (Equatorial Guinea) (3)
  14  239  -  55.94  0.27  -  2.30 
Israel  -  114  -  -  3.47  -  1.36 
North Sea  7  5  -  59.51  5.75  -  15.81 
Ecuador  -  26  -  -  -  -  - 
China  4  -  -  54.40  -  -  6.75 
Total Consolidated Operations  62  781  10  55.76  2.54  27.96 $5.05 
Equity Investee (4)
  2  -  6  59.51  -  36.03    
Total  64  781  16 $55.87 $2.54 $31.20    
Year Ended December 31, 2008                      
United States                      
Wattenberg Field  15�� 146  5 $71.41 $7.39 $52.19 $3.12 
Other US  25  249  4  78.02  8.55 $47.51  7.91 
Total US (2)
  40  395  9  75.53  8.12 $50.15  6.08 
Alba Field (Equatorial Guinea) (3)
  15  206  -  88.95  0.27  -  2.17 
Israel  -  139  -  -  3.10  -  1.07 
North Sea  10  5  -  100.56  10.54  -  12.63 
Ecuador  -  22  -  -  -  -  - 
China  4  -  -  82.66  -  -  7.03 
Total Consolidated Operations  69  767  9  82.60  5.04  50.15 $4.90 
Equity Investee (4)
  2  -  6  96.77  -  58.81    
Total  71  767  15 $82.96 $5.04 $53.45    
Year Ended December 31, 2007                      
United States                      
Wattenberg Field  13  163  - $68.19 $5.52 $- $2.68 
Other US  29  249  -  46.76  8.82  -  6.72 
Total US (2)
  42  412  -  53.22  7.51  -  5.26 
Alba Field (Equatorial Guinea) (3)
  15  132  -  71.27  0.29  -  2.89 
Israel  -  111  -  -  2.79  -  1.14 
North Sea  13  6  -  76.47  6.54  -  7.68 
Ecuador  -  26  -  -  -  -  - 
China  4        58.79        7.08 
Argentina (5)
  3  -  -  46.79  -  -  11.79 
Total Consolidated Operations  77  687  -  60.61  5.26  - $4.62 
Equity Investee (4)
  2  -  6  74.87  -  48.87    
Total  79  687  6 $60.94 $5.26 $48.87    
              
Average
 
  
Sales Volumes
 
Average Sales Price
 
Production Cost
 
  
Crude Oil
 
Natural Gas
��
NGLs
 
Crude Oil
 
Natural Gas
 
NGLs
   
  
MBopd (1)
 
MMcfpd
 
MBpd
 
Per Bbl (2)
 
Per Mcf (2)
 
Per Bbl
 
Per BOE (3)
 
Year Ended December 31, 2008
               
United States
  40  395  9 $75.53 $8.12 $50.15 $10.43 
West Africa (4) (5)
  15  206  -  88.95  0.27  -  2.17 
North Sea
  10  5  -  100.56  10.54  -  14.30 
Israel
  -  139  -  -  3.10  -  1.07 
Ecuador
  -  22  -  -  -  -  - 
Other International (6)
  4  -  -  82.66  -  -  15.94 
Total Consolidated Operations
  69  767  9  82.60  5.04  50.15 $7.84 
Equity Investee (7)
  2  -  6  96.77  -  58.81    
Total
  71  767  15 $82.96 $5.04 $53.45    
Year Ended December 31, 2007
                      
United States
  42  412  - $53.22 $7.51  - $8.49 
West Africa (4) (5)
  15  132  -  71.27  0.29  -  2.89 
North Sea
  13  6  -  76.47  6.54  -  9.81 
Israel
  -  111  -  -  2.79  -  1.14 
Ecuador
  -  26  -  -  -  -  - 
Other International (6)
  7  -  -  53.69  -  -  12.06 
Total Consolidated Operations
  77  687  -  60.61  5.26  - $6.99 
Equity Investee (7)
  2  -  6  74.87  -  48.87    
Total
  79  687  6 $60.94 $5.26 $48.87    
Year Ended December 31, 2006
                      
United States
  46  452  - $50.68 $6.61  - $8.12 
West Africa (4) (5)
  18  45  -  62.51  0.37  -  2.86 
North Sea
  4  8  -  67.43  8.00  -  10.08 
Israel
  -  93  -  -  2.72  -  1.60 
Ecuador
  -  25  -  -  -  -  - 
Other International (6)
  7  -  -  52.05  -  -  9.74 
Total Consolidated Operations
  75  623  -  54.47  5.55  - $6.97 
Equity Investee (7)
  2  -  6  66.60  -  40.10    
Total
  77  623  6 $54.75 $5.55 $40.10    
(1)
In 2008, volumes include the effect of crudeAverage production cost includes oil sales in excess of volumes produced of 1 MBopd in West Africa. During 2007, crude oil sales volumes equaled volumes produced. In 2006, volumes include the effect of crude oil sales in excess of volumes produced of 1 MBopd in West Africa and crude oil sales less than volumes produced of 1 MBopd in other international.
gas operating costs and workover and repair expense and excludes production and ad valorem taxes.
(2)
Average crude oil sales prices for the US reflect reductions of $2.13 per Bbl (2009), $22.06 per Bbl (2008), and $13.68 per Bbl (2007), and $11.41 per Bbl (2006) from hedging activities. Average natural gas sales prices reflect increases of $0.23 per Mcf (2008), and $1.12 per Mcf (2007) from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis.
(3)
Average crude oil sales prices for West Africa reflect reductions of $5.57 per Bbl (2009), $7.59 per Bbl (2008), and $2.19 per Bbl (2007) from hedging activities. We did not hedge West Africa crude oil sales in 2006. Average naturalNatural gas sales prices in the US reflect an increase of $0.23 per Mcf (2008), an increase of $1.12 per Mcf (2007), and a reduction of $0.25 per Mcf (2006) from hedging activities.
(3)
Average production costs include oil and gas operating costs, workover and repair expense, production and ad valorem taxes, and transportation expense.
(4)
Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. Sales to these plants are based on a BTU equivalent and then converted to a dry gas equivalent volume. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting. The volumes produced by the LPG plant are included in the crude oil information. The price on an Mcf basis has been adjusted to reflect the Btu content of gas sales.


(5)
Equatorial Guinea natural gas volumes include sales to the LNG plant of 163 MMcfpd for 2008 and 78 MMcfpd for 2007.  There were no natural gas sales to the LNG plant before 2007.
(4)
Other International crude oil volumes include China and Argentina (through February 2008). Other International natural gas volumes include Argentina (through February 2008).
(7)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
(5)We sold our Argentina assets in February 2008.

15


Revenues from sales of crude oil and natural gas have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.
 
At December 31, 2008,2009, our operated properties accounted for approximately 61%60% of our total production. Being the operator of a property improves our ability to directly influence production levels and the timing of projects, while also enhancing our control over operating expenses and capital expenditures.
 
Productive Wells—The number of productive crude oil and natural gas wells in which we held an interest as ofat December 31, 20082009 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
  Crude Oil Wells Natural Gas Wells Total 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
  Gross  Net Gross  Net Gross Net 
United States
                            
Northern Region
  7,567  5,853.8  4,835  3,384.6  12,402  9,238.4   7,825   6,119.0  5,028   3,637.9  12,853  9,756.9 
Southern Region
  833  796.0  252  105.7  1,085  901.7   799   593.0  392   175.0  1,191  768.0 
West Africa
  3  1.2  20  7.7  23  8.9 
Equatorial Guinea  4   1.7  20   7.7  24  9.4 
Israel  -   -  5   2.4  5  2.4 
North Sea
  17  3.5  9  1.2  26  4.7   22   4.7  8   1.0  30  5.7 
Israel
  -  -  6  2.8  6  2.8 
Ecuador
  -  -  5  5.0  5  5.0   -   -  3   3.0  3  3.0 
China
  14  8.0  1  0.6  15  8.6   15   8.6  1   0.6  16  9.2 
Total
  8,434  6,662.5  5,128  3,507.6  13,562  10,170.1   8,665   6,727.0  5,457   3,827.6  14,122  10,554.6 
                   
Multiple Completions
  -  -  16  3.3  16  3.3 
 
Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. A net well is deemed to exist when the sum of fractional ownership working interests in gross wells equals one. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above.
 
Developed and Undeveloped Acreage—Developed and undeveloped acreage (including both leases and concessions) held at December 31, 20082009 was as follows:
 
 
Developed Acreage
 
Undeveloped Acreage
  Developed Acreage Undeveloped Acreage 
 
Gross
 
Net
 
Gross
 
Net
  Gross Net Gross Net 
(thousands)         
United States
 
(in thousands)
          
Onshore
  1,352  893  1,361  1,014   1,625  956  1,603  1,262 
Offshore
  164  103  556  300   134  84  524  362 
Total United States
  1,516  996  1,917  1,314   1,759  1,040  2,127  1,624 
             
International
                          
Equatorial Guinea
  45  15  618  250   140  53  523  212 
Cameroon
  -  -  1,125  563   -  -  1,125  563 
Israel  62  29  1,790  796 
North Sea (1)
  48  6  266  54   50  6  229  44 
Israel
  62  29  1,823  807 
Ecuador
  12  12  852  852   12  12  849  849 
China
  7  4  -  -   7  4  -  - 
Suriname
  -  -  7,740  6,363   -  -  3,087  1,389 
Other International (2)
  -  -  1,830  1,142 
Nicaragua  -  -  1,977  1,977 
Cyprus  -  -  1,136  795 
India  -  -  694  347 
Total International
  174  66  14,254  10,031   271  104  11,410  6,972 
Total Worldwide (3)
  1,690  1,062  16,171  11,345 
Total (2)
  2,030  1,144  13,537  8,596 
 


(1)
The North Sea includes acreage in the UK and the Netherlands. In 2008, we sold our interest in Norway acreage consisting of approximately 411,000 gross (127,000 net) undeveloped acres.
(2)
Other International includes India and Cyprus.
(3)
Approximately 258,000687,000 gross acres (176,000(407,000 net acres) will expire in 2009, 662,0002010; 1.4 million gross acres (385,000(975,000 net acres) will expire in 2010,2011; and 1,370,000172,000 gross acres (1,285,000(121,000 net acres) will expire in 20112012 if production is not established or we take no other action to extend the terms.
terms of the leases or concessions.
 
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well.
Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well.
 
A gross acre is any leased acre in which a working interest is owned. A net acre is comprised of the total of the owned working interest(s) in a gross acre expressed in a fractional format.
 

16

Drilling Activity—The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows:
 
 
Net Exploratory Wells
 
Net Development Wells
  Net Exploratory Wells Net Development Wells   
 
Productive
 
Dry
 
Total
 
Productive (1)
 
Dry
 
Total
  Productive Dry Total Productive Dry Total Total 
               
Year Ended December 31, 2009               
United States               
Northern Region  2.5  1.0  3.5  516.9  1.0  517.9  521.4 
Southern Region  1.6  0.6  2.2  15.4  1.0  16.4  18.6 
Equatorial Guinea (1)
  0.5  -  0.5  -  -  -  0.5 
Israel (1)
  1.1  -  1.1  -  -  -  1.1 
North Sea  -  -  -  1.0  -  1.0  1.0 
China  -  -  -  0.6  -  0.6  0.6 
Total  5.7  1.6  7.3  533.9  2.0  535.9  543.2 
Year Ended December 31, 2008
                                   
United States
                                   
Northern Region
  1.0  -  1.0  837.2  42.0  879.2   1.0  -  1.0  837.2  42.0  879.2  880.2 
Southern Region
  14.6  2.0  16.6  30.9  2.0  32.9   14.6  2.0  16.6  30.9  2.0  32.9  49.5 
West Africa
  1.3     1.3  -  -  - 
Equatorial Guinea (1)
  1.3  -  1.3  -  -  -  1.3 
North Sea
  -  0.4  0.4  0.6  0.3  0.9   -  0.4  0.4  0.6  0.3  0.9  1.3 
Israel
  -  -  -  -  -  - 
Suriname
  -  0.5  0.5  -  -  -   -  0.5  0.5  -  -  -  0.5 
Total
  16.9  2.9  19.8  868.7  44.3  913.0   16.9  2.9  19.8  868.7  44.3  913.0  932.8 
Year Ended December 31, 2007
                                         
United States
                                         
Northern Region
  13.9  1.9  15.8  738.0  24.5  762.5   13.9  1.9  15.8  738.0  24.5  762.5  778.3 
Southern Region
  0.3  2.6  2.9  19.6  3.1  22.7   0.3  2.6  2.9  19.6  3.1  22.7  25.6 
West Africa
  2.6  0.5  3.1  -  -  - 
North Sea
  0.5  -  0.5  -  -  - 
Equatorial Guinea (1)
  2.1  0.5  2.6  -  -  -  2.6 
Cameroon (1)
  0.5  -  0.5  -  -  -  0.5 
Israel
  -  -  -  0.4  -  0.4   -  -  -  0.4  -  0.4  0.4 
Argentina (2)
  -  0.1  0.1  6.7  -  6.7 
Total
  17.3  5.1  22.4  764.7  27.6  792.3 
Year Ended December 31, 2006
                   
United States
                   
Northern Region
  5.5  4.6  10.1  521.4  4.6  526.0 
Southern Region
  0.8  4.4  5.2  145.2  0.9  146.1 
West Africa
  -  0.4  0.4  1.8  -  1.8 
North Sea
  -  -  -  1.1  -  1.1   0.5  -  0.5  -  -  -  0.5 
Argentina (2)
  -  -  -  7.6  -  7.6   -  0.1  0.1  6.7  -  6.7  6.8 
Total
  6.3  9.4  15.7  677.1  5.5  682.6   17.3  5.1  22.4  764.7  27.6  792.3  814.7 
 
(1)
ExcludesIncludes successful exploratory wells drilled but not yet completed.
producing.
(2)     Our assets in Argentina were sold February 2008.
(2)We sold our assets in Argentina in February 2008.
 
A productive well is an exploratory, development or a developmentextension well that is not a dry well. A dry well (hole) is an exploratory, development, or a developmentextension well foundthat proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
 
AnAs defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find and produce crude oila new field or natural gas in an unproved area, to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir. A development well for purposes of the table above and as defined in the rules and regulations of the SEC, is a well drilled within the proved areapart of a crude oil or natural gas reservoirdevelopment project, which is defined as the means by which petroleum resources are brought to the depthstatus of a stratigraphic horizon known to be productive.economically producible. The number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. Completion refers to the installation of permanent equipment for the production of crude oil or natural gas, or, in the case of a dry hole,well, to the reporting of abandonment to the appropriate agency.authority that the well has been abandoned.
 


In addition to the wells drilled and completed in 20082009 included in the table above, at December 31, 2008,2009, we were in the process of drilling or completing 269152 gross (215.4(113.2 net) wells in the Northern region of our US operations, two gross (1.2(0.7 net) onshore wells in the Southern region of our US operations, two gross (0.6 net) wells in the deepwater Gulf of Mexico, one gross (0.5(0.3 net) well in Equatorial Guinea,the North Sea, and one gross (0.4(0.6 net) well in Israel.China.
 
Marketing Activities—We seek opportunities to enhance the value of our US natural gas production by marketing directly to end-users and aggregating natural gas to be sold to natural gas marketers and pipelines. We also engage in the purchase and sale of third-party crude oil and natural gas production. Such third-party production may be purchased from non-operators who own working interests in our wells or from other producers’ properties in which we own no interest. We sell our natural gas production at both market-based and fixed prices. In 2008,2009, approximately 15%28% of natural gas sales were made pursuant to long-term contracts under either fixed or market-based prices.
 
Crude oil, condensate and NGLs produced in the US and foreign locations are generally sold under short-term contracts at market-based prices adjusted for location and quality. In China, we sell crude oil into the local market under a long-term contract at market-based prices. In Israel, we sell natural gas under long-term contracts at negotiated prices. Crude oil and condensate are distributed through pipelines and by trucks or tankers to gatherers, transportation companies and refineries.


Delivery Commitments   Some of our natural gas sales contracts specify the delivery of a fixed and determinable quantity of product. We have commitments to deliver approximately 220 Bcf of natural gas, net to our interest, to various customers in Israel through the year 2022. Approximately 90% of this amount will be delivered by 2015. We expect to fulfill the delivery commitments with proved developed and proved undeveloped reserves from the Mari-B and other nearby fields in Israel and we do not expect any shortfall. See International – Eastern Mediterranean (Israel and Cyprus).
 
Significant Purchaser—Suncor Glencore Energy Marketing (Suncor)UK Ltd (Glencore) was the largest single non-affiliated purchaser of 20082009 production and purchased our share of crude oilproduction from the WattenbergAlba field in Colorado.Equatorial Guinea under a short-term sales contract, subject to renewal.  Sales to SuncorGlencore accounted for 22%25% of 20082009 crude oil sales, or 13%16% of 20082009 total oil and gas sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2008.2009. We believe that the loss of any one purchaser would not have a material effect on our financial position or results of operations since there are numerous potential purchasers of our production.
 
Hedging Activities—Commodity prices were volatile in 20082009 and prices for crude oil and natural gas are affected by a variety of factors beyond our control. We have used derivative instruments, and expect to do so in the future, in order to achieve a more predictablereduce commodity price uncertainty and increase cash flow by reducingpredictability relating to the marketing of our exposure to commodity price fluctuations.crude oil and natural gas. For additional information, see Item 1A. Risk Factors—Factors – Hedging transactions may limit our potential gains and Hedging transactions, receivables and cash investments expose usWe are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
RegulationsTermination of Contracts   See Item 1A. Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country’s unsettled economic and political environment, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Current Conditions in Ecuador, and Item 8. Financial Statements and Supplementary Data – 3. Impairments.
 
Regulations
Government Regulation—Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the international, federal, state and local levels. Crude oil and natural gas development and production activities are subject to various laws and regulations (and orders of regulatory bodies pursuant thereto) governing a wide variety of matters, including, among others, allowable rates of production, transportation, prevention of waste and pollution and protection of the environment. Laws affecting the crude oil and natural gas industry are under constant review for amendment or expansion and frequently increase the regulatory burden on companies. Our ability to economically produce and sell crude oil and natural gas is affected by a number of legal and regulatory factors, including federal, state and local laws and regulations in the US and laws and regulations of foreign nations. Many of these governmental bodies have issued rules and regulations that are often difficult and costly to comply with, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory burden on the crude oil and natural gas industry increases our costs of doing business and consequently affects our profitability. See Item 1A. Risk Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.
 
Examples of US federal agencies with regulatory authority over our exploration for, and production and sale of, crude oil and natural gas include:
 
·
the Bureau of Land Management (BLM) and the Minerals Management Service (MMS), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act have certain authority over our operations on federal lands, particularly in the Rocky Mountains and deepwater Gulf of Mexico;
·
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration, which under laws such as the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the


Clean Water Act, and the Occupational Safety and Health Act and the recent Final Mandatory Reporting of Greenhouse Gases Rule have certain authority over environmental, health and safety matters affecting our operations as discussed below;
·
the Federal Energy Regulatory Commission, which under laws such as the Energy Policy Act of 2005 has certain authority over the marketing and transportation of crude oil and natural gas we produce onshore and from the deepwater Gulf of Mexico;
·
the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our US onshore and deepwater Gulf of Mexico operations; and
·
other federal agencies with certain authority over our business, such as the Internal Revenue Service and the SEC, as well as the NYSE upon which shares of our common stock are traded.
 
In January 2010, the BLM announced that it will be issuing a new draft oil and gas leasing policy that will require, among other things, a more detailed environmental review prior to leasing oil and natural gas resources, increased public engagement in the development of master leasing and development plans prior to leasing areas where intensive new oil and gas development is anticipated, and a comprehensive parcel review process.  As the policy has not yet been released, we are not able to determine the impact these potential leasing policy changes may have on our business.

18
Most of the states within which we operate have separate agencies with authority to regulate related operational and environmental matters.  Examples of such regulation on the operational side include the Greater Wattenberg Area Special Well Location Rule 318A, which was adopted by the Colorado Oil and Gas Conservation Commission to address oil and gas well drilling, production, commingling and spacing in the Wattenberg field, and more recently, the same commission’sCommission’s December 10, 2008 approval of a comprehensive update to statewide rules governing oil and gas operations in Colorado. These rules will bewere reviewed by the Colorado legislature in its 2009 session and will becomebecame effective in the second quarter of 2009, addressing areas such as public drinking water protection, monitoring and disclosure of chemicals used in drilling operations, erosion management and environment and wildlife protection. On the environmental side, Colorado Regulation Seven and requirements for storm water management plans were adopted by the Colorado Department of Environmental Quality, under delegation from the US Environmental Protection Agency,EPA, to regulate air emissions, water protection and waste handling and disposal relating to our oil and gas exploration and production.
 
Some of the counties and municipalities within which we operate have adopted regulations or ordinances that impose additional restrictions on our oil and gas exploration and production.  An example is Garfield County, Colorado, which provides local land and road use restrictions affecting our Piceance basin operations and requires us to post bonds to secure any restoration obligations.
 
Our international operations are subject to legal and regulatory oversight by energy-related ministries of our host countries, each having certain relevant energy or hydrocarbons laws.  Examples of these ministries include the Ecuador Ministry of Petroleum and Mines,Nonrenewable Natural Resources, the Equatorial Guinea Ministry of Mines, Industry and Energy, the Israel Ministry of National Infrastructures, and the UK Department of Energy and Climate Change.  An example of a law affecting our international operations is the UK Finance Act of 2006, which increased the income tax rate on our UK operations effective January 1, 2006.
 
Environmental Matters—As a developer, owner and operator of crude oil and natural gas properties, we are subject to various federal, state, local and foreign country laws and regulations relating to the discharge of materials into, and the protection of, the environment. We must take into account the cost of complying with environmental regulations in planning, designing, drilling, operating and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production waste products, water and air pollution control procedures, and the remediation of petroleum-product contamination. Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us or prior owners or operators in accordance with current laws or otherwise, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups to prevent future contamination. The US Environmental Protection AgencyEPA and various state agencies have limited the disposal options for hazardous and non-hazardous wastes. The owner and operator of a site, and persons that treated, disposed of or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The US Environmental Protection Agency,EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from treatment as hazardous wastes may in the future be designated as hazardous wastes and, therefore, be subject to considerably more rigorous and costly operating and disposal requirements. See Item 1A. Risk Factors—Factors – We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.
 
Federal and state occupational safety and health laws require us to organize information about hazardous materials used, released or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards.
 
Certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
 


We have made and will continue to make expenditures in our efforts to comply with environmental requirements. We do not believe that we have, to date, expended material amounts in connection with such activities or that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
Competition
 
Competition
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals and drilling and incomepartnership programs. Many of our competitors are large, well established companies. Such companies may be able to pay more for seismic and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. See Item 1A. Risk Factors— – We face significant competition and many of our competitors have resources in excess of our available resources.
Geographical Data
 

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Geographical Data
We have operations throughout the world and manage our operations by country. Information is grouped into five components that are all primarily in the business of crude oil, natural gas and NGL acquisition, exploration, development and production: United States, West Africa, Eastern Mediterranean, North Sea, Israel, and Other International, Corporate and Marketing. For more information, seeSee Item 8. Financial Statements and Supplementary Data—Data – Note 15—15. Segment Information.
 
Employees
 
Our total number of employees increased during the year from 1,398 at December 31, 2007 to 1,571 at December 31, 2008.2008 to 1,630 at December 31, 2009. The 20082009 year-end employee count includes 182154 foreign nationals working as employees in Ecuador, China, Israel, the UK, Equatorial Guinea and Cameroon. We regularly use independent contractors and consultants to perform various field and other services.
 
Offices
 
Our principal corporate office, including our offices for US and international operations, is located at 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain additional offices in Ardmore, Oklahoma and Denver, Colorado and in China, Cameroon, Ecuador, Equatorial Guinea, Israel and the UK.
 
Title to Properties
 
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that arewould not so material as tomaterially detract substantially from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty 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, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under production sharing contracts or exploration licenses.
Available Information
 
Available Information
Our website address is www.nobleenergyinc.com. Available on this website under “Investor Relations—Investor Relations Menu—“Investors – Investors Menu – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC.
 
Also posted on our website, and available in print upon request made by any stockholder to the Investor Relations Department, are charters for our Audit Committee; Compensation, Benefits and Stock Option Committee; Corporate Governance and Nominating Committee; and Environment, Health and Safety Committee. Copies of the Code of Business Conduct and Ethics, and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are posted on our website under the “Corporate Governance” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
 


In 2008, we submitted the annual certification of our Chief Executive Officer regarding compliance with the NYSE’s corporate governance listing standards, pursuant to Section 303A.12(a) of the NYSE Listed Company Manual.
Item 1A.  Risk Factors
 
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K.
If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic environment intensifies many of these risks.
Future economic conditions in the US and key international markets may materially adversely impact our operating results.
The US and other world economies are slowly recovering from a recession which began in 2008 and extended into 2009. Growth has resumed, but is modest.  There are likely to be significant long-term effects resulting from the recession and credit market crisis, including a future global economic growth rate that is slower than what was experienced in recent years.  In addition, more volatility may occur before a sustainable, yet lower, growth rate is achieved.   Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate will result in decreased demand growth for our crude oil and natural gas production as well as lower commodity prices, which will reduce our cash flows from operations and our profitability.

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Crude oil and natural gas prices are volatile and a substantial reduction in these prices could adversely affect our results and the price of our common stock.
 
Our revenues, operating results and future rate of growth depend highly upon the prices we receive for our crude oil and natural gas production. Historically, the markets for crude oil and natural gas have been volatile and are likely to continue to be volatile in the future. For example, the NYMEX daily settlement price for the prompt month oil contract in 20082009 ranged from a high of $145.29$81.37 per barrel to a low of $33.87$33.98 per barrel. The NYMEX daily settlement price for the prompt month natural gas contract in 20082009 ranged from a high of $13.58$6.07 per MMBtu to a low of $5.29$2.51 per MMBtu. The markets and prices for crude oil and natural gas depend on factors beyond our control. These factors include demand for crude oil and natural gas, which fluctuates with changes in market and economic conditions, and other factors, including:
 
 ·worldwide and domestic supplies of crude oil and natural gas;
 ·actions taken by foreign oil and gas producing nations;
 ·political conditions and events (including instability or armed conflict) in crude oil or natural gas producing regions;
 ·the level of global crude oil and natural gas inventories;
 ·the price and level of imported foreign imports;crude oil and natural gas;
 ·the price and availability of alternative fuels;fuels, including coal and biofuels;
 ·the availability of pipeline capacity and infrastructure;
 ·the availability of crude oil transportation and refining capacity;
 ·weather conditions;
 ·electricity dispatch;generation;
 ·domestic and foreign governmental regulations and taxes; and
 ·the overall economic environment.
 
Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:
 
 ·limiting our financial condition, liquidity, and/or ability to finance planned capital expenditures and results of operations;
 ·reducing the amount of crude oil and natural gas that we can produce economically;
 ·causing us to delay or postpone some of our capital projects;
 ·reducing our revenues, operating income and cash flows;
·reducing the carrying value of our crude oil and natural gas properties; or
 ·limiting our access to sources of capital, such as equity and long-term debt.
 
In addition, significant declines in the forward commodity price curves may result in the following:
·a reduction in the carrying value of our crude oil and natural gas properties; or
·a reduction in the carrying value of goodwill.
We recorded asset impairment charges during 2009. If commodity prices decline during 2010, there could be additional impairments of our oil and gas assets or other investments or an impairment of goodwill.
Market conditions may restrict our ability to obtain funds for future development and working capital needs, which may limit our financial flexibility.
During 2009, credit markets recovered but remain vulnerable to unpredictable shocks should weaker than expected economic growth persist.  We have a significant development project inventory and an extensive exploration portfolio, which will require substantial future investment. We and our partners will need to seek financing in order to fund these or other activities. Our future access to capital, as well as that of our partners and contractors, could be limited if the debt or equity markets are constrained. This could significantly delay development of our property interests.
Failure to fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require substantial capital expenditures especially in the case of our active drilling programs, such as the Wattenberg field, and our significant exploration and development programs in the deepwater Gulf of Mexico, West Africa and Israel. Significant capital investments on our inventory of major development projects will start next year and are estimated to be approximately $1 billion per year in 2010 and 2011.  First production from these projects is not expected until 2011 and thereafter. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt  issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to debt or capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access capital markets on an economic basis to meet these requirements. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.

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Indebtedness may limit our liquidity and financial flexibility.
As of December 31, 2009, we had long-term indebtedness of $2 billion (excluding unamortized discount), with $382 million drawn under our bank credit facility. Our indebtedness represented 25% of our total book capitalization at December 31, 2009.
Our indebtedness affects our operations in several ways, including the following:
·a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
·we may be at a competitive disadvantage as compared to similar companies that have less debt;
·the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
·additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
·additional financing in the future is likely to have higher costs due to the negative impact of the credit market crisis which restricted access to the bond markets;
·changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving credit facility; and
·we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities such as our pending acquisition of additional US Rocky Mountain assets. A higher level of indebtedness increases the risk that our liquidity may become impaired and we default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, crude oil and natural gas prices and financial, business and other factors will affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.
Hedging transactions may limit our potential gains.
In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements.
Global commodity price fluctuation has been significant in 2009. Such volatility disrupts our ability to forecast and, as a result, we may become even more reliant on our hedging program.  In trying to manage our exposure to commodity price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our futures contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices.  We cannot assure that our hedging transactions will reduce the risk or minimize the effect of volatility in crude oil or natural gas prices.

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We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from trade, joint venture, and other receivables.  We sell our crude oil, natural gas and NGLs to a variety of purchasers.   In addition, we are the operator on large joint venture development projects such as Aseng in Equatorial Guinea and Tamar in Israel. As operator of the joint ventures, we pay joint venture expenses and bill our nonoperating partners for their respective shares of joint venture costs. Some of our purchasers and joint venture partners are not as creditworthy as we are and may experience liquidity problems. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including our largest international crude oil purchaser; however, not all of our trade credit is protected through guarantees or credit support.  Nonperformance by a trade creditor or joint venture partner could result in significant financial losses.
We also monitor the creditworthiness of our counterparties on an ongoing basis. However, disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in financial market conditions or a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract.  To mitigate counterparty credit risk we conduct our hedging activities with a diverse group of major financial institutions.  We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be “net settled” at the time of election. “Net settlement” refers to a process by which all transactions between counterparties are resolved into a single amount owed by one party to the other.
During periods of falling commodity prices, such as in late 2008 and first quarter 2009, our hedge receivable positions increase, which increases our counterparty exposure. If the creditworthiness of our counterparties, which are major financial institutions, deteriorates and results in their nonperformance, we could incur a significant loss.
We have over $1 billion in cash and cash equivalents invested in money market funds and short-term deposits with major financial institutions. During the first half of 2009, we shortened the duration of our bank deposits and held over 50% of our cash and cash equivalents in US Treasury securities. We maintained this investment posture well into the third quarter of 2009 before we started to reduce our US Treasury holdings in favor of reinvestment back into money market funds and time deposits with highly rated banks. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. However, we are unable to predict sudden changes in solvency of our financial institutions. In the event of a bank failure, we could incur a significant loss.
We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unfortuitous events such as blowouts, cratering, fire and explosion and loss of well control which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. Our international operations are also subject to political risk.
In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believe to be economic. Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets. Although we believe the coverages and amounts of insurance carried are adequate, we may not have sufficient protection against some of the risks we face, because we chose not to insure certain risks, insurance is not available on commercially reasonable terms or actual losses exceed coverage limits. If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have an adverse impact on our financial condition, results of operations and cash flows.
Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and negative effects on our operating results.
We currently have an extensive inventory of major development projects, several of which will take years before first production, including the Aseng oil project, Tamar, Gunflint, and others.  Some of these projects, such as oil and gas projects in West Africa, have a great deal of complexity. This level of development will require significant effort from our management and technical personnel as well as place additional burden on our financial resources and internal financial controls. We may not be able to attract and retain personnel with the skills necessary to bring complicated projects to successful conclusions.
In addition, we will have increased dependency on third-party technology and service providers and other vendors for these complex projects.  Significant delays in delivery of essential items or performance of services, cost overruns, vendor insolvency, or other critical supply failure, could adversely affect development of our projects.
We may not be able to manage these and other risks effectively.

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We may be unable to make attractive acquisitions, integrate acquired businesses and/or assets, or adjust to the effects of divestitures, causing a disruption to our business.
One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current business, such as our Patina Merger in 2005, our purchase of U.S. Exploration in 2006 and the pending acquisition of additional US Rocky Mountain assets.  This may present greater risks for us than those faced by peer companies that do not consider acquisitions as a part of their business strategy. We cannot provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the acquisition due to capital market constraints, even if such capital is available on commercially acceptable terms. If we acquire another business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own, or could assume unidentified or unforeseeable liabilities, resulting in a loss of value.
We also engage in portfolio rationalization, such as the sale of our interest in Argentina in 2008, and the majority of our Gulf of Mexico shelf properties in 2006. These transactions can also result in changes in operations, systems, or management and other personnel.
Organizational modifications due to acquisitions, divestitures or portfolio rationalizations, or other strategic changes can alter the risk and control environments, disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these difficulties could be overcome, we cannot provide assurance that the anticipated benefits of any acquisition, divestiture or other strategic change would be realized.
Estimates of crude oil and natural gas reserves are not precise.
 
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their value, including many factors that are beyond our control. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact manner. Our reserveIn accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we adopted effective December 31, 2009, our reserves estimates are based on year-end commodity12-month average prices; therefore, reservereserves quantities will change when actual prices increase or decrease. The estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
 
 ·historical production from the area compared with production from other areas;
 ·the assumed effects of regulations by governmental agencies, including the impact of the SEC’s new oil and gas company reservereserves reporting requirements;
 ·assumptions concerning future crude oil and natural gas prices;
 ·future operating costs;
 ·severance and excise taxes;
 ·development costs; and
 ·workover and remedial costs.
 
For these reasons, estimates of the economically recoverable quantities of crude oil and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery and estimates of the future net cash flows expected from them prepared by different engineers or by the same engineers but at different times may vary substantially. Accordingly, reservereserves estimates may be subject to upward or downward adjustment, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.
 

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Additionally, because some of our reservereserves estimates are calculated using volumetric analysis, those estimates are less reliable than the estimates based on a lengthy production history. Volumetric analysis involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. In addition, realization or recognition of proved undeveloped reserves will depend on our development schedule and plans. A change in future development plans for proved undeveloped reserves could cause the discontinuation of the classification of these reserves as proved.
Failure to fund continued capital expenditures could adversely affect our properties.
Our acquisition, exploration, and development activities require substantial capital expenditures especially in the case of our active drilling programs, such as the Wattenberg field, and our significant exploration and development program in West Africa. Historically, we have funded our capital expenditures through a combination of cash flows from operations, our revolving bank credit facility and debt and equity issuances. Future cash flows are subject to a number of variables, such as the level of production from existing wells, prices of crude oil and natural gas, and our success in finding, developing and producing new reserves. If revenues were to decrease as a result of lower crude oil and natural gas prices or decreased production, and our access to capital were limited, we would have a reduced ability to replace our reserves, resulting in a decrease in production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital budget, we may not be able to access debt, equity or other methods of financing on an economic basis to meet these requirements, particularly in the current economic environment. If we are not able to fund our capital expenditures, interests in some properties might be reduced or forfeited as a result.
The current recession could have a material adverse impact on our financial position, results of operations and cash flows.
The oil and gas industry is cyclical in nature and tends to reflect general economic conditions. The US and other world economies are in a recession which could last well into 2009 and beyond. The recession may lead to significant fluctuations in demand and pricing for our crude oil and natural gas production, such as the decline in commodity prices which occurred during 2008 and into 2009. Our profitability will likely be significantly affected by decreased demand and lower commodity prices. Due to lower commodity prices, we recorded asset impairment charges during fourth quarter 2008. If commodity prices continue to decline, there could be additional impairments of our operating assets or an impairment of goodwill. Our future access to capital, as well as that of our partners and contractors, could be limited due to tightening credit markets that could inhibit development of our property interests.  Some of our longer term projects require significant investment and may be delayed due to capital constraints.  In addition, if drilling costs decline significantly, our long-term drilling rig contracts may require us to pay rates higher than the current market.  See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Contractual Obligations for additional information on drilling rig contracts.
Our international operations may be adversely affected by economic and political developments.
We have significant international crude oil and natural gas operations compared to companies we consider to be our peers, with approximately 44% of our consolidated sales volumes in 2008 coming from international operations. These operations may be adversely affected by political and economic developments, including the following:
·war, terrorist acts, civil disturbances, or territorial disputes, such as may occur in regions that encompass our operations, including Ecuador, Israel and West Africa;
·loss of revenue, property and equipment as a result of actions taken by foreign crude oil and natural gas producing nations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts, such as may occur pursuant to the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea;
·changes in taxation policies, such as the UK Finance Act of 2006, which increased the income tax rate on our UK operations effective January 1, 2006, and the China Petroleum Special Profits Tax enacted in 2006, which imposed an excise tax on crude oil produced in the country;
·laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;
·foreign exchange restrictions;
·international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business, such as the UK; and
·other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
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Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues.
 
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:
 
 ·pipeline ruptures and spills;
 ·fires;
 ·explosions, blowouts and cratering;
 ·formations with abnormal pressures;
 ·equipment malfunctions;
 ·hurricanes, such as Gustav and Ike in 2008, which could affect our operations in areas such as the Gulf Coast and deepwater Gulf of Mexico, and cyclones, which could affect our operations offshore China; and
 ·other natural disasters.
 
Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others.

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Exploration and development drilling may not result in commercially productive reserves.
 
We do not always encounter commercially productive reservoirs through our drilling operations. The wells we drill or participate in may not be productive and we may not recover all or any portion of our investment in those wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically, and area well data and other data may be limited or less-developed in some of the international areas in which we explore. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project. Our efforts will be unprofitable if we drill dry holes or wells that are productive but do not produce enough reserves to return a profit after drilling, operating and other costs. Further, our drilling operations may be curtailed, delayed or canceled as a result of a variety of factors, including:
 
 ·unexpected drilling conditions;
 ·title problems;
 ·pressure or other irregularities in formations;
 ·equipment failures or accidents;
 ·adverse weather conditions;
 ·compliance with environmental and other governmental requirements; and
 ·increases in the cost of, or shortages or delays in the availability of, drilling rigs and equipment.
 
We may be unable to make attractive acquisitions or integrate acquired businesses and/or assets, and any inability to do so may disrupt our business.
One aspect of our business strategy calls for acquisitions of businesses and assets that complement or expand our current business, such as our Patina Merger and our purchase of U.S. Exploration.  This may present greater risks for us than those faced by peer companies that do not consider acquisitions as a part of their business strategy. We cannot provide assurance that we will be able to identify attractive acquisition opportunities. Even if we do identify attractive opportunities, we cannot provide assurance that we will be able to complete the acquisition due to capital market constraints or even if such capital is available on commercially acceptable terms. Additionally, if we acquire another business, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt ongoing business, distract management and employees, increase expenses and adversely affect results of operations. Even if these difficulties could be overcome, we cannot provide assurance that the anticipated benefits of any acquisition would be realized.
We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs.
From time to time, in varying degrees, political developments and federal and state laws and regulations affect our operations. In particular, price controls, taxes and other laws relating to the crude oil and natural gas industry, changes in these laws and changes in administrative regulations have affected and in the future could affect crude oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations.

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Our operations are subject to complex international, federal, state and local environmental laws and regulations including, for example, in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act and the Occupational Safety and Health Act. Environmental laws and regulations change frequently and the implementation of new, or the modification of existing, laws or regulations could negatively impact our operations. The discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation. In addition, we may incur costs and penalties in addressing regulatory agency procedures involving instances of possible non-compliance.
Potential regulations regarding climate change could alter the way we conduct our business.
As awareness of climate change issues increases, governments around the world are beginning to address the matter. This may result in new environmental regulations that may unfavorably impact us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows.
The unavailability or high cost of drilling rigs, equipment, supplies, personnel and other oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
 
Our industry is cyclical and, from time to time, there is a shortage of drilling rigs, equipment, supplies or qualified personnel. During these periods, the costs of rigs, equipment and supplies are substantially greater and their availability may be limited, particularly in areas of high activity and demand in which we concentrate, such as the Rocky Mountains and deepwater Gulf of Mexico, and in some international locations that typically have more limited availability of equipment and personnel, such as Ecuador, Israel and West Africa. During periods of increasing levels of exploration and production in response to strong demand for crude oil and natural gas, the demand for oilfield services and the costs of these services increase. Additionally, these services may not be available on commercially reasonable terms.
 
We mayIn the current economy, even though commodity prices have fallen from the high levels experienced in 2008, the costs of drilling rigs, equipment and supplies, though somewhat reduced, have not have enough insurancedecreased to cover all of the risks we face, which could result in significant financial exposure.
Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters and other unfortuitous events such as blowouts, cratering, fire and explosion and loss of well control which can result in damage to or destruction of wells or production facilities, injury to persons, loss of life, or damage to property and the environment. In accordance with industry practices, we maintain insurance against many, but not all, potential perils confronting our operations and in coverage amounts and deductible levels that we believeexisted before the run-up in commodity prices that occurred in the first half of 2008.  If drilling costs decline significantly, our long-term drilling rig contracts may require us to pay rates higher than the current market. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations for additional information on drilling rig contracts.  As a result, an increase in profits may be reasonable. Consistent with that profile, our insurance program is structured to provide us financial protection from unfavorable loss severity resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets. Although we believe the coverages and amounts of insurance carried are adequate, we may not have sufficient protection against some of the risks we face, because we chose not to insure certain risks, insurance is not availablemore dependant on commercially reasonable terms or actual losses exceed coverage limits. If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have an adverse impact on our financial condition, results of operations and cash flows.cost reduction than in previous years.
 
Exploration and development in the deepwater Gulf of Mexico involves significant financial risks.
Much of the deepwater Gulf of Mexico area lacks the physical and oilfield service infrastructure necessary for production. As a result, development of a deepwater discovery, such as Gunflint, may be a lengthy process and require substantial capital investment. We participate in certain other projects, such as Isabela and Double Mountain, for which we are not the operator. If we are not the operator of a project, we may have limited ability to exercise influence over the project or its costs. This could prevent the realization of targeted return on capital or lead to unexpected future losses.
In addition, there is limited availability of suitable drilling rigs, drilling equipment, support vessels, production and transportation infrastructure, qualified operating personnel, and deepwater drilling rigs are typically subject to long-term contracts. This can lead to difficulty and delays in consistently obtaining drilling rigs and other equipment and services at acceptable rates, which, in turn, may lead to projects being delayed or increased costs. This also makes it difficult to estimate the timing of production.
We face significant competition and many of our competitors have resources in excess of our available resources.
 
We operate in the highly competitive areas of crude oil and natural gas exploration, exploitation, acquisition and production. We face intense competition from a large number of independent, technology-driven companies as well as both major and other independent crude oil and natural gas companies in a number of areas such as:
 
 ·seeking to acquire desirable producing properties or new leases for future exploration;
 ·marketing our crude oil and natural gas production;
 ·seeking to acquire the equipment and expertise necessary to operate and develop properties; and
 ·attracting and retaining employees with certain skills.
 

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Many of our competitors have financial and other resources substantially in excess of those available to us. For example, in the deepwater Gulf of Mexico we compete with major integrated crude oil and natural gas companies and in international locations such as the North Sea we compete with major integrated crude oil and natural gas companies as well as state-controlled multinational companies.
In addition, the economic recession has increased competitive pressures. Crude oil and natural gas exploration and production companies, as well as service and drilling companies, are striving to improve efficiency and profitability, primarily through cost reduction. This highly competitive environment could have an adverse impact on our business.
The marketability of our Rocky Mountain and Gulf of Mexico production is dependent upon transportation and processing facilities over which we may have no control.
The marketability of our production from the Rocky Mountain area and the deepwater Gulf of Mexico depends in part upon the availability, proximity and capacity of pipelines, natural gas gathering systems and processing facilities. We deliver crude oil and natural gas produced from these areas 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.
Our international operations may be adversely affected by economic and political developments.
We have significant international crude oil and natural gas operations compared to companies we consider to be our peers, with approximately 44% of our 2009 consolidated sales volumes coming from international operations. These operations may be adversely affected by political and economic developments, including the following:
·war, terrorist acts, civil disturbances, or territorial disputes, such as may occur in regions that encompass our operations, including Ecuador, Israel and West Africa;
·loss of revenue, property and equipment as a result of actions taken by foreign crude oil and natural gas producing nations, such as expropriation or nationalization of assets and renegotiation, modification or nullification of existing contracts, such as may occur pursuant to the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea;
·changes in taxation policies, such as the UK Finance Act of 2006, which increased the income tax rate on our UK operations effective January 1, 2006, and the China Petroleum Special Profits Tax enacted in 2006, which imposed an excise tax on crude oil produced in the country;
·laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;
·foreign exchange restrictions;
·international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business, such as the UK; and
·other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
We may not have enough insurance to cover any loss of property resulting from these risks.
Our operations and investment in Ecuador may be adversely affected by the country's unsettled economic and political environment.
The economic and political environment in Ecuador has become increasingly unsettled. We are aware that the Government of Ecuador is taking steps to renegotiate contracts or, in some cases, remove international oil and gas companies from its borders. We continue to have significant delinquent accounts and unpaid invoices related to electricity sales from our Machala power plant, and we recently entered into independent power purchase agreements for such sales, the long-term effect of which on payment is unknown. On August 24, 2009, we became aware that our proposed plan of development for the Amistad field (offshore Ecuador), which had been submitted to Ecuador’s National Bureau of Hydrocarbons, had been rejected. In addition, on December 31, 2009, Ecuador’s state oil company (Petroecuador) requested that Ecuador’s Minister of Nonrenewable Natural Resources commence termination of our production sharing contract. On February 11, 2010, the Minister notified us of Petroecuador's request by delivering to us a copy of a letter of non-compliance dated December 31, 2009. The Minister provided us with 60 business days to respond to the allegations contained in the letter. We are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a further reduction in the value of our investments in Ecuador which, as of December 31, 2009, had a net book value of approximately $72 million. See Item 8. Financial Statements and Supplementary Data – Note 3. Asset Impairments.
 

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Our level of indebtednessWe are subject to various governmental regulations and environmental risks that may limit our financial flexibility.cause us to incur substantial costs.
 
As of December 31, 2008, we had long-term indebtedness of $2.2 billion (excluding unamortized discount), with $1.6 billion drawn underFrom time to time, in varying degrees, political developments and federal and state laws and regulations affect our bank credit facility. Our indebtedness represented 26% of our total book capitalization at December 31, 2008.
Our level of indebtedness affects our operations in several ways, including the following:
·a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;
·we may be at a competitive disadvantage as compared to similar companies that have less debt;
·the covenants contained in the agreements governing our outstanding indebtedness and future indebtedness may limit our ability to borrow additional funds, pay dividends and make certain investments and may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;
·additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
·additional financing in the future is likely to have higher costs dueoperations. In particular, price controls, taxes and other laws relating to the negative impact of the current credit market crisis which has restricted access to the bond markets;
·changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and availability of future financing, and lower ratings will increase the interest rate and fees we pay on our revolving credit facility; and
·we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our acquisition, exploration and development activities. A higher level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and reduce our level of indebtedness depends on future performance. General economic conditions, crude oil and natural gas pricesindustry, changes in these laws and changes in administrative regulations have affected and in the future could affect crude oil and natural gas production, operations and economics. We cannot predict how agencies or courts will interpret existing laws and regulations or the effect these adoptions and interpretations may have on our business or financial condition.
Our business is subject to laws and regulations promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil and natural gas, as well as safety matters. Legal requirements are frequently changed and subject to interpretation and we are unable to predict the ultimate cost of compliance with these requirements or their effect on our operations. We may be required to make significant expenditures to comply with governmental laws and regulations.
Our operations are subject to complex international, federal, state and local environmental laws and regulations including, for example, in the case of federal laws, the Comprehensive Environmental Response, Compensation and Liability Act, as amended, the Resource Conservation and Recovery Act, as amended, the Oil Pollution Act of 1990, the Clean Air Act, the Clean Water Act and the Occupational Safety and Health Act. Environmental laws and regulations change frequently and the implementation of new, or the modification of existing, laws or regulations could negatively impact our operations. The discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to significant liabilities on our part to the government and third parties and may require us to incur substantial costs of remediation. In addition, we may incur costs and penalties in addressing regulatory agency procedures involving instances of possible non-compliance.
Increased regulation of business practices could result in increased operating costs.
The current trend is toward increased regulation of business practices and additional reporting requirements. For example the EPA has recently issued the Final Mandatory Reporting of Greenhouse Gases Rule, which requires many suppliers of fossil fuels or industrial chemicals, manufacturers of vehicles and engines, and other factorsfacilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to begin collecting greenhouse gas emissions data under a new reporting system on January 1, 2010 with the first annual report due March 31, 2011. We will affectbe subject to these new reporting requirements, which will result in additional effort on the part of our personnel. In addition, other pending legislation, such as the pending climate change legislation that includes establishing a “cap and trade” system for restricting greenhouse gas emissions in the US, or pending hydraulic fracturing legislation that would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act, if enacted, will require an unprecedented compliance effort on the part of companies in the oil and gas industry. We may be required to make significant expenditures to comply with additional reporting requirements.
The proposed US federal budget for fiscal year 2011 includes certain provisions that, if passed as originally submitted, will have an adverse effect on our financial position, results of operations, and cash flows.
On February 1, 2010, the Obama administration released its proposed federal budget for fiscal year 2011.  The proposed budget would repeal many tax incentives and deductions that are currently used by US oil and gas companies and impose new taxes. The provisions include: elimination of the ability to fully deduct intangible drilling costs in the year incurred; increases in the taxation of foreign source income; levy of an excise tax on Gulf of Mexico oil and gas production; repeal of the manufacturing tax deduction for oil and gas companies; increase in the geological and geophysical amortization period for independent producers; and implementation of a fee on non-producing leases located on federal lands. 
If these proposals are enacted, our future performance. Manytaxes will increase, potentially significantly, which would have a negative impact on our net income and cash flows. This could also reduce our drilling activities. Since none of these factors are beyond our control andproposals have yet to be voted on or become law, we do not know the ultimate impact theymay not be able to generate sufficient cash flow to pay the interesthave on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.business.
 
Hedging transactions may limitThe adoption of pending climate change legislation could result in increased operating costs, create delays in our potential gains.
In order to manage our exposure to price risks inobtaining air pollution permits for new or modified facilities, and reduce demand for the marketing of our crude oil and natural gas we enterproduce.
In June 2009, the House of Representatives passed the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill. The Senate’s version, The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, has been introduced, but has not passed. Although these bills include several differences that require reconciliation before becoming law, both bills contain the basic feature of establishing a “cap and trade” system for restricting greenhouse gas emissions in the US. Under such system, certain sources of greenhouse gas emissions would be required to obtain greenhouse gas emission “allowances” corresponding to their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of greenhouse gas emission allowances declines each year, the cost or value of allowances is expected to escalate significantly. The ultimate outcome of this legislative initiative remains uncertain.   In addition to the pending climate legislation, the EPA has issued greenhouse gas monitoring and reporting regulations that went into effect January 1, 2010, and require reporting by regulated facilities by March 2011 and annually thereafter.  Beyond measuring and reporting, the EPA issued an “Endangerment Finding” under section 202(a) of the Clean Air Act, concluding greenhouse gas pollution threatens the public health and welfare of current and future generations.  The EPA has proposed regulation that would require permits for and reductions in greenhouse gas emissions for certain facilities, and may issue final rules this year. Since approximately 60% of our 2009 crude oil production and 51% of our 2009 natural gas production derive from the US, any laws or regulations that may be adopted to restrict or reduce emissions of US greenhouse gases could require us to incur increased operating costs, and could have an adverse effect on demand for the crude oil and natural gas price hedging arrangements with respect to a portion of our expected production. Our hedges, consisting of a series of contracts, are limited in duration, usually for periods of one to four years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if crude oil and natural gas prices rise over the price established by the arrangements. In trying to manage our exposure to price risk, we may end up hedging too much or too little, depending upon how our crude oil or natural gas volumes and our production mix fluctuate in the future. In addition, hedging transactions may expose us to the risk of financial loss in certain circumstances, including instances in which our production is less than expected; there is a widening of price basis differentials between delivery points for our production and the delivery point assumed in the hedge arrangement; the counterparties to our future contracts fail to perform under the contracts; or a sudden unexpected event materially impacts crude oil or natural gas prices. We cannot assure that our hedging transactions will reduce the risk or minimize the effect of any decline in crude oil or natural gas prices.
Hedging transactions, receivables and cash investments expose us to counterparty credit risk.
Our hedging transactions also expose us to risk of financial loss if a counterparty fails to perform under a contract.  To mitigate counterparty credit risk we conduct our hedging activities with a diverse group of major financial institutions.  We use master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. We also monitor the creditworthiness of our counterparties on an ongoing basis. However, the current disruptions occurring in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the hedging contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.produce.
 

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During periods of falling commodity prices, such as in late 2008, our hedge receivable positions increase, which increases our exposure. If the creditworthiness of our counterparties, which are major financial institutions, deteriorates and results in their nonperformance, we
Federal hydraulic fracturing legislation could incur a significant loss.
In addition to hedging transactions, we are exposed to risk of financial loss from trade and other receivables.  We sell our crude oil, natural gas and NGLs to a variety of purchasers.  Some of these parties are not as creditworthy as we are and may experience liquidity problems.  Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including from our largest international crude oil purchaser; however, we do not have all of our trade credit enhanced through guarantees or credit support.  Nonperformance by a trade creditor could result in significant financial losses.
We have over $1.0 billion in cash and cash equivalents, including investments in US Treasury securities and short-term cash investments with major financial institutions. In response to the credit market crisis, we have shortened the duration of our investment maturities and have increased our investments in US Treasury securities. However, we are unable to predict sudden changes in solvency of our financial institutions. In the event of a bank failure, we could incur a significant loss.
Information technology systems implementation issues could disrupt our internal operations, increase our costs and adversely affectrestrict our financial results oraccess to oil and gas reserves.
Several proposals are before Congress that, if implemented, would subject the process of hydraulic fracturing to regulation under the Safe Drinking Water Act. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into rock formations to stimulate natural gas production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs. Such legislation could have a significant impact on our development of the Wattenberg field, our largest onshore US field.
Although it is not possible at this time to predict the final outcome of the legislation regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could significantly increase our operating, capital and compliance costs as well as delay our ability to reportdevelop oil and gas reserves.
Derivatives regulation could restrict our financial results.ability to execute commodity derivative instruments as a hedge against fluctuating commodity prices.
Various measures are being proposed by committees of Congress, the US Treasury Department, and other agencies to restrict the use of over-the-counter (OTC) derivative instruments.  These proposals include, but are not limited to, requiring cash collateral on all OTC derivatives and requiring all OTC derivatives to be executed and settled through an exchange system.
Although we do not currently know the exact form any final legislation or rule-making activity will take, any restriction on the use of OTC instruments could have a significant impact on our business. Limits on the use of OTC instruments could significantly reduce our ability to execute strategic price hedges to reduce price uncertainty and to protect cash flows.  In addition, cash collateral requirements could create significant liquidity issues and exchange system trades may restrict our ability to execute derivative instruments to fit our strategic needs.
Healthcare reform legislation could adversely impact us.
On November 7, 2009, the House of Representatives passed its healthcare reform bill, the Affordable Health Care for America Act, H.R. 3962. Among other initiatives, this bill authorizes the creation of a national public plan that would negotiate rates with providers and would be offered through a new national health insurance exchange market. On December 24, 2009, the Senate passed its own version of a healthcare reform bill, the Patient Protection and Affordable Care Act, H.R. 3590. The Senate bill contains no provision for a public plan but does authorize the creation of at least two multi-state plans.
At this time, it remains unclear how or when the differences between the two bills will be resolved, or if a final bill ultimately will be enacted. Various healthcare reform proposals have also emerged at the state level. We cannot predict what healthcare initiatives, if any, will be implemented at the federal or state level, or the effect any future legislation or regulation will have on us. However, an expansion in government’s role in the US healthcare industry could have a significant impact on our employment benefits and related costs.
 
We haveface various risks associated with the trend toward increased activism against oil and gas development activities.
Opposition toward oil and gas drilling and development activity has been growing domestically as well as in countries belonging to the Organization for Economic Cooperation and Development (OECD), an international group of member countries sharing a commitment to democratic government and market economy.  Companies in the processpetroleum industry, such as us, are often the target of implementing a new Enterprise Resource Planning software systemactivist efforts regarding safety, human rights, environmental compliance and business practices.  Anti-development activists are working to, replace our various legacy systems. Our implementation is based on a phased approach, the first phaseamong other things, reduce access to federal and state government lands and delay or cancel certain projects such as development of which was implemented fourth quarter 2007. We implemented additional phases in 2008 and expect to implement additional phases in 2009. As a part of this effort, we are transitioning data and changing certain processes and this may be more expensive, time consuming and resource intensive than planned. Any disruptions that may occuroil shale.
Future activist efforts could result in the implementationfollowing:
·delay or denial of drilling permits;
·shortening of lease terms or reduction in lease size;
·restrictions on installation or operation of gathering or processing facilities;
·damaging publicity about us;
·increased costs of doing business;
·reduction in demand for our products; and
·other adverse affects on our ability to develop our properties and expand production
Our need to incur costs associated with responding to these initiatives or operation of this systemcomplying with any resulting new legal or any future systemsregulatory requirements resulting from these activities that are substantial and not adequately provided for, could increasehave a material adverse effect on our expensesbusiness, financial condition and adversely affect our ability to report in an accurate and timely manner our financial position, results of operations and cash flows and to otherwise operate our business.operations.

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Provisions in our Certificate of Incorporation and Delaware law may inhibit a takeover of us.
 
Under our Certificate of Incorporation, our Board of Directors is authorized to issue shares of our common or preferred stock without approval of our stockholders.shareholders. Issuance of these shares could make it more difficult to acquire us without the approval of our Board of Directors as more shares would have to be acquired to gain control. In addition, Delaware law imposes restrictions on mergers and other business combinations between us and any holder of 15% or more of our outstanding common stock. These provisions may deter hostile takeover attempts that could result in an acquisition of us that would have been financially beneficial to our stockholders.shareholders.
 
Disclosure Regarding Forward-LookingForward-Looking Statements
 
This annual report on Form 10-K and the documents incorporated by reference in this report contain forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events. These forward-looking statements include, among others, the following:
 
 ·our growth strategies;
 ·our ability to successfully and economically explore for and develop crude oil and natural gas resources;
 ·anticipated trends in our business;
 ·our future results of operations;
 ·our liquidity and ability to finance our acquisition, exploration and development activities;effect of current volatility in the credit markets;
 ·our outlook on global economic conditionsliquidity and markets;ability to finance our exploration, development, and acquisition activities;
 ·market conditions in the oil and gas industry;
 ·our ability to make and integrate acquisitions; and
 ·the impact of governmental regulation.
 
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “anticipate,” “estimate” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.
 

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Item 1B.  Unresolved Staff Comments
 
None.
 
Item 3.  Legal Proceedings
 
Purchaser Bankruptcy     – We havehad an exposure from crude oil sales for the months of June and July 2008 to SemCrude, L.P. (SemCrude), a subsidiary of SemGroup, L.P. (SemGroup).  On July 22, 2008, SemGroup, including SemCrude, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code under Case Number 08-11525 (BLS) in the United States Bankruptcy Court for the District of Delaware.
As of December 31, During 2008, we had adetermined that the carrying value of our receivable of approximately $71 million from SemCrude. We have determined that it is probable thatshould be reduced by $38 million. Based upon the confirmation of SemCrude's plan for reorganization on October 26, 2009 and further based upon a portion of the receivable is uncollectible. Therefore, in third quarter 2008,settlement reached with SemCrude on October 27, 2009, we further reduced the carrying value of theour receivable by $12 million. We have received distributions of approximately $21 million from SemCrude receivable and recognized a pre-tax charge of $38 million forbelieve the probable loss. We are pursuing various legal remedies to protect our interests. We believe that ultimate disposition of this matter will not have a material adverse affect on our financial position, results of operations, or cash flows.to be finally determined.
 
Legal Proceedings     – We are among a group of 18 defendants named in a lawsuit filed August 23, 2002 by Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana.  The lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s.  Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999.  Dore has delivered documents alleging approximately $140 million in damages.  Trial is currently set for April 27, 2009.  We intend to vigorously defend against these allegations and believe that our share of damages, if any, will not have a material adverse effect on our financial position, results of operations, or cash flows.
We are involved in various legal proceedings, including the foregoing matters in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we do not believe that the ultimate disposition of such proceedings will have a material adverse effect on our financial position, results of operations or cash flows.
 
Item 4.  Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to a vote of security holders duringin the fourth quarter of 2008.2009.
 
Executive Officers
 
The following table sets forth certain information, as of February 19, 2009,18, 2010, with respect to our executive officers.
 
Name Age Position
Charles D. Davidson (1)
 5859 Chairman of the Board, President, Chief Executive Officer and Director
David L. Stover (2)
 5152 Executive Vice President, Chief Operating Officer
Chris TongKenneth M. Fisher (3)
 5248 Senior Vice President, Chief Financial Officer
Ted D. Brown (4)
 5354 Senior Vice President, Northern Region
Rodney D. Cook (5)
 5152 Senior Vice President, International
Susan M. Cunningham (6)
 5354 Senior Vice President, Exploration
Arnold J. Johnson (7)
 5354 Senior Vice President, General Counsel and Secretary
Andrea Lee Robison (8)
 5051 Vice President, Human Resources

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(1)
Charles D. Davidson was elected President and Chief ExecutiveExecutive Officer of Noble Energy in October 2000 and Chairman of the Board in April 2001.2001, also serving as President until April 2009 (at which time Mr. Stover assumed that position). Prior to October 2000, he served as President and Chief Executive Officer of Vastar Resources, Inc. from March 1997 to September 2000 (Chairman from April 2000) and was a Vastar Director from March 1994 to September 2000. From September 1993 to March 1997, he served as a Senior Vice President of Vastar. From 1972 to October 1993, he held various positions with ARCO.
(2)David L. Stover was elected President and Chief Operating Officer of Noble Energy in April 2009. Prior thereto, he served as Executive Vice President and Chief Operating Officer of Noble Energy infrom August 2006. Prior thereto, he2006 to April 2009. He served as Senior Vice President of North America and Business Development from July 2004 through July 2006. He2006, and he served as Noble Energy'sEnergy’s Vice President of Business Development from December 2002 through June 2004. Previous to his employment with Noble Energy, he was employed by BP America, Inc. as Vice President, Gulf of Mexico Shelf from September 2000 to August 2002. Prior to joining BP, Mr. Stover was employed by Vastar, as Area Manager for Gulf of Mexico Shelf from April 1999 to September 2000, and prior thereto, as Area Manager for Oklahoma/Arklatex from January 1994 to April 1999. From 1979 to 1994, he held various positions with ARCO.
 

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(3)Chris Tong
Kenneth M. Fisher was elected a Senior Vice President and Chief Financial Officer of Noble Energy in January 2005.November 2009. Prior to joining Noble Energy, Mr. Fisher served as Executive Vice President of Finance for Upstream Americas for Shell from July 2009 to November 2009. Prior to his most recent position with Shell, Mr. Fisher served as Director of Strategy & Business Development for Royal Dutch Shell plc in The Hague from August 2007 to July 2009.  He served as Executive Vice President of Strategy & Portfolio for Shell’s downstream business in London from January 2005 he hadto August 2007 and was responsible for leading global strategy, portfolio, fuels development and biofuels activity along with central health, safety and environment functions. Mr. Fisher joined Shell in August 2002 and served as SeniorChief Financial Officer for Shell Oil Products U.S. until December 2004. As Chief Financial Officer for Shell Oil Products U.S., he was responsible for U.S. oil products finance, information technology and contracting and procurement activities. Prior to joining Shell, he held positions of increasing responsibility with General Electric (GE) from 1984 to 2002, including Vice President and Chief Financial Officer for Magnum Hunter Resources, Inc. since August 1997. Prior thereto, he was Senior Vice Presidentof the Aircraft Engines Services division and a Singapore-based position as Director of Finance & Business Development of Tejas Acadian Holding Company and its subsidiaries including Tejas Gas Corp., Acadian Gas Corporation and Transok, Inc., all of which were wholly-owned subsidiaries of Tejas Gas Corporation. Mr. Tong held these positions since August 1996, and served in other treasury positions with Tejas beginning August 1989. From 1980 to 1989, Mr. Tong served in various energy lending capacities with several commercial banking institutions. Prior to his banking career, Mr. Tong served over a year with Superior Oil Company as a Reservoir Engineering Assistant.GE’s Asia Pacific plastics business.
(4)Ted D. Brown was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the Northern Region of our North America division. He served as Vice President, responsible for the same region, from August 2006 to April 2008 and as a vice president of that division since joining us upon our acquisition of Patina in May 2005. He served as Senior Vice President of Patina from July 2004 to May 2005. Prior thereto he served as Director, Piceance Basin Asset along with Engineering Manager for Williams and Barrett Resources since 1993 and, before that, in various positions with Union Pacific Resources and Amoco Production Company.
(5)Rodney D. Cook was elected a Senior Vice President of Noble Energy in April 2008 and is currently responsible for the International division. He served as Vice President of Noble Energy, responsible for the Southern Region of our North America division, from August 2006 to April 2008 and as a vice president of that division from May 2005 to August 2006. He served as Manager of our West Africa and Middle East Business Unit from 2002 to 2005. Prior thereto he served as Operations Manager of the International division since 1996. From 1980 to 1996 he held various positions with Noble Energy. Prior to joining Noble Energy in 1980, Mr. Cook held various positions with Texas Pacific Oil.
(6)
Susan M. Cunningham was elected a Senior Vice President of Noble Energy in April 2001 and is currently responsible for our world-wide exploration. Prior to joining Noble Energy, Ms. Cunningham was Texaco’s Vice President of worldwide exploration from April 2000 to March 2001. From 1997 through 1999, she was employed by Statoil, beginning in 1997 as Exploration Manager for deepwater Gulf of Mexico, appointed a Vice President in 1998 and responsible, in 1999, for Statoil’s West Africa exploration efforts. She joined Amoco Canada in 1980 as a geologist and held various exploration and development positions with Amoco Production Company until 1997.
(7)Arnold J. Johnson was elected Senior Vice President, General Counsel and Secretary of Noble Energy in July 2008. Prior thereto, he served as Vice President, General Counsel and Secretary of Noble Energy since February 2004. He served as Associate General Counsel and Assistant Secretary of Noble Energy from January 2001 through January 2004. Previous to his employment with Noble Energy, he served as Senior Counsel for BP America, Inc. from October 2000 to January 2001. Mr. Johnson held several positions as an attorney for Vastar and ARCO from March 1989 through September 2000, most recently as Assistant General Counsel and Assistant Secretary of Vastar from 1997 through 2000. From 1980 to March 1989, he held various positions with ARCO.
(8)Andrea Lee Robison was elected to the position of Vice President of Noble Energy in November 2007 and is responsible for Human Resources. Prior thereto, she served as Director of Human Resources from May 2002 through October 2007. Prior to joining us, Ms. Robison was Manager of Human Resources for the Gulf of Mexico Shelf for BP America, Inc. from September 2000 through April 2002. Prior to her employment at BP, she served as HR Director at Vastar from 1997 through September 2000, and Compensation Consultant from January 1994 through 1996. From 1980 through 1993 she held various positions with ARCO.
 

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PART II
Item 5.     Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
Common Stock.Stock Our common stock, $3.33 1/3 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.
 
Stock Prices and Dividends by Quarters.Quarters The high and low sales price per share of our common stock on the NYSE and quarterly dividends paid per share were as follows:
 
        Dividends 
  High  Low  Per Share 
2007         
First quarter $60.69  $46.33  $0.075 
Second quarter  65.50   58.81   0.120 
Third quarter  70.55   58.17   0.120 
Fourth quarter  81.64   69.69   0.120 
2008            
First quarter $81.35  $ 69.18  $0.120 
Second quarter  103.83   75.79   0.180 
Third quarter  102.79   51.18   0.180 
Fourth quarter  54.01   33.15   0.180 
  High  Low  Dividends Per Share 
2008         
First Quarter $81.35  $69.18  $0.12 
Second Quarter  103.83   75.79   0.18 
Third Quarter  102.79   51.18   0.18 
Fourth Quarter  54.01   33.15   0.18 
2009            
First Quarter $58.24  $40.33  $0.18 
Second Quarter  69.07   50.86   0.18 
Third Quarter  70.35   51.49   0.18 
Fourth Quarter  74.09   62.25   0.18 
 
On January 27, 2009,26, 2010, the Board of Directors declared a quarterly cash dividend of 0.18 cents$0.18 per common share, which will be paid February 23, 200922, 2010 to shareholders of record on February 9, 2009.8, 2010.
 
Transfer Agent and Registrar.Registrar   The transfer agent and registrar for theour common stock is Wells Fargo Bank, N.A., 161 North Concord Exchange, South St. Paul, MN, 55075.
 
Stockholders’ Profile.Profile   Pursuant to the records of the transfer agent, as of February 6, 2009,5, 2010, the number of holders of record of our common stock was 744.
Stock Repurchases    The following table summarizes repurchases of our common stock was 775.occurring fourth quarter 2009.
 
Period 
Total Number
of Shares Purchased (1)
 Average Price Paid Per Share Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs Approximate Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs 
        (in thousands) 
10/01/09 - 10/31/09  - $-  -  - 
11/01/09 - 11/30/09  320  66.72  -  - 
12/01/09 - 12/31/09  -  -  -  - 
Total  320 $66.72  -  - 
(1)
Stock Repurchases. We did not repurchase anyrepurchases during the period related to stock received by us from employees for the payment of our common stock in the fourth quarter of 2008.withholding taxes due on shares issued under stock-based compensation plans.
 
Equity Compensation Plan Information.Information   The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2008.2009.
 
      Number of securities 
      remaining available 
    Weighted-averagefor future issuance 
 Number of securities exercise price ofunder equity 
 to be issued upon outstanding compensation plans 
 exercise of  options, warrants(excluding securities 
Plan Category outstanding options and rights reflected in column (a))  Number of Securities to be Issued Upon Exercies of Outstanding Options, Warrants and Rights Weighted Average Exercise Price of Outstanding Options, Warrants and Rights Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) 
 (a)  (b) (c)  (a) (b) (c) 
Equity compensation plans approved by security holders  6,082,375  $41.41  5,319,463 
Equity compensation plans not approved by security holders  -   -  - 
Equity Compensation Plans Approved by Security Holders       6,820,291 $45.01        5,274,898 
Equity Compensation Plans Not Approved by Security Holders                        -                           -                        - 
Total  6,082,375  $41.41  5,319,463        6,820,291 $45.01        5,274,898 
 

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Stock Performance Graph.Graph    This graph shows our cumulative total shareholder return over the five-year period from December 31, 2003,2004, to December 31, 2008.2009. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and our peer group of companies. At December 31, 2008,2009, our peer group of companies consisted of the following:
 
Anadarko Petroleum Corp.Murphy Oil Corp.
Apache Corp.Newfield Exploration Company
Cabot Oil & Gas Corp.Pioneer Natural Resources Company
Chesapeake Energy Corp.Plains Exploration and Production Company
Devon Energy Corp.Range Resources Corp.
EOG Resources, Inc.Southwestern Energy Company
Forest Oil Corp.XTO Energy Inc.
 
The comparison assumes $100 was invested on December 31, 2003,2004, in our common stock, in the S&P 500 Index and in our peer group and assumes that all of the dividends were reinvested.

 
 
 12/03 12/04 12/05 12/06 12/07  12/08 
Year Ended December 31, 2004 2005 2006 2007 2008 2009 
Noble Energy, Inc. $100.00 $139.34 $ 182.87 $223.97 $365.44 $228.44  $100.00 $131.24 $160.73 $262.26 $163.94 $240.11 
S&P 500  100.00  110.88  116.33  134.70  142.10  89.53   100.00  104.91  121.48  128.16  80.74  102.11 
Peer Group  100.00  133.07  208.21  207.03  300.86  187.65   100.00  156.47  155.59  226.10  141.02  200.93 
 


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Item 6.  Selected Financial Data
 
  Year Ended December 31, 
  2008  2007  
2006 (1)
  
2005 (2)
  2004 
  (in millions, except as noted) 
Revenues and Income               
Total revenues $3,901  $3,272  $2,940  $2,187  $1,351 
Income from continuing operations  1,350   944   678   646   314 
Net income  1,350   944   678   646   329 
Per Share Data                    
Basic earnings per share -                    
Income from continuing operations $7.83  $5.52  $3.86  $4.20  $2.69 
Net income  7.83   5.52   3.86   4.20   2.82 
Cash dividends  0.660   0.435   0.275   0.150   0.100 
Year-end stock price  49.22   80.66   49.07   40.30   30.83 
Basic weighted average shares outstanding  173   171   176   154   117 
Cash Flows                    
Net cash provided by operating activities $2,285  $2,017  $1,730  $1,240  $ 708 
Additions to property, plant and equipment  1,971   1,414   1,357   786   554 
Acquisitions  292   -   412   1,111   - 
Financial Position                    
Cash and cash equivalents  1,140   660   153   110   180 
Commodity derivative instruments - current  437   15   35   29   29 
Property, plant, and equipment, net  9,004   7,945   7,171   6,199   2,181 
Goodwill  759   761   781   863   - 
Total assets  12,384   10,831   9,589   8,878   3,436 
Long-term obligations -                    
Long-term debt  2,241   1,851   1,801   2,031   880 
Deferred income taxes  2,174   1,984   1,758   1,201   180 
Commodity derivative instruments  2   83   329   758   10 
Asset retirement obligations  184   131   128   279   175 
Other  300   337   275   280   69 
Shareholders' equity  6,309   4,809   4,114   3,090   1,460 
Operations Information                    
Consolidated crude oil sales (MBopd)  69   77   75   57   44 
Average realized price ($/Bbl) (3)
 $82.60  $60.61  $54.47  $45.35  $34.48 
Consolidated natural gas sales (MMcfpd)  767   687   623   508   367 
Average realized price ($/Mcf) (3)
 $5.04  $5.26  $5.55  $5.78  $4.76 
Consolidated NGL sales (MBpd) (4)
  9   -   -   -   - 
Average realized price ($/Bbl) $50.15  $-  $-  $-  $- 
Proved Reserves                    
Crude oil, condensate and NGL reserves (MMBbl)  311   329   296   291   193 
Natural gas reserves (Bcf)  3,315   3,307   3,231   3,091   1,987 
Total reserves (MMBoe)  864   880   835   806   525 
Number of employees  1,571   1,398   1,243   1,171   559 
  Year Ended December 31, 
  2009 2008 2007 
2006 (1)
 
2005 (2)
 
(millions, except as noted)           
Revenues and Income (Loss)           
Total Revenues $2,313 $3,901 $3,272 $2,940 $2,187 
Net Income (Loss)  (131) 1,350  944  678  646 
Per Share Data                
Earnings (Loss) Per Share                
Basic $(0.75)$7.83 $5.52 $3.86 $4.20 
Diluted  (0.75) 7.58  5.45  3.79  4.12 
Cash Dividends Per Share  0.720  0.660  0.435  0.275  0.150 
Year-End Stock Price Per Share  71.22  49.22  80.66  49.07  40.30 
Weighted Average Shares Outstanding                
Basic  173  173  171  176  154 
Diluted  173  176  173  179  157 
Cash Flows                
Net Cash Provided by Operating Activities $1,508 $2,285 $2,017 $1,730 $1,240 
Additions to Property, Plant and Equipment  1,268  1,971  1,414  1,357  786 
Acquisitions  -  292  -  412  1,111 
Financial Position                
Cash and Cash Equivalents  1,014  1,140  660  153  110 
Commodity Derivative Instruments - Current  13  437  15  35  29 
Property, Plant, and Equipment, Net  8,916  9,004  7,945  7,171  6,199 
Goodwill  758  759  761  781  863 
Total Assets  11,807  12,384  10,831  9,589  8,878 
Long-term Obligations                
Long-Term Debt  2,037  2,241  1,851  1,801  2,031 
Deferred Income Taxes  2,076  2,174  1,984  1,758  1,201 
Commodity Derivative Instruments  17  2  83  329  758 
Asset Retirement Obligations  181  184  131  128  279 
Other  349  300  337  275  280 
Shareholders' Equity  6,157  6,309  4,809  4,114  3,090 
Operations Information                
Consolidated Crude Oil Sales (MBopd)  62  69  77  75  57 
Average Realized Price ($/Bbl) (3)
 $55.76 $82.60 $60.61 $54.47 $45.35 
Consolidated Natural Gas Sales (MMcfpd)  781  767  687  623  508 
Average Realized Price ($/Mcf) (3)
 $2.54 $5.04 $5.26 $5.55 $5.78 
Consolidated NGL Sales (MBpd) (4)
  10  9  -  -  - 
Average Realized Price ($/Bbl) $27.96 $50.15 $- $- $- 
Proved Reserves                
Crude Oil, Condensate and NGL Reserves (MMBbls)  336  311  329  296  291 
Natural Gas Reserves (Bcf)  2,904  3,315  3,307  3,231  3,091 
Total Reserves (MMBoe)  820  864  880  835  806 
Number of Employees  1,630  1,571  1,398  1,243  1,171 
 
(1)
Includes effect of acquisition of U.S. Exploration and sale of Gulf of Mexico shelf properties. See Item 8. Financial Statements and Supplementary Data—Note 4—Acquisitions and Divestitures for additional information.
(2)Includes effect of Patina Merger.
(3)
Prices include effects of oil and gas hedging activities. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6.  Derivative Instruments and Hedging Activities.
(4)
Prior to 2008, US NGL sales volumes were included with natural gas volumes. Effective in 2008 we began reporting US NGLs separately where we have the right to take title, which lowered the comparative natural gas sales volumes for 2008.

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Item 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
We are an independent energy company engaged in worldwide crude oil, natural gas and NGL exploration and production. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with key international operations offshore Israel the North Sea and West Africa.
 
OurThe accompanying consolidated financial statements, including the notes thereto, contain detailed information that should be referred to in conjunction with the following discussion.
 
EXECUTIVE OVERVIEW
 
We are a worldwide producer of crude oil and natural gas. Our strategy is to achieve growth in earnings and cash flows through the continued expansion of a high quality portfolio of producing assets that is diversified among US and international projects;projects, crude oil and natural gas;gas, and near, medium and long-term opportunities.
 
FinancialStrategy   We endeavor to continue our strong historic growth trend (7.9% average annual production growth rate from 2000 to 2009) to deliver superior value to our shareholders.  We primarily focus on organic growth from exploration and Operating Results - 2008 wasdevelopment drilling, and we augment that with a successful year for us as evidenced by our record earnings, cash flows provided bystrong, periodic new business development (mergers and acquisition) capability. We concentrate on basins or plays where we have strategic competitive advantage and which we believe offer superior returns. Core operating activities and production. We extended our acreage position bothareas are the onshore and offshore US and pursued new exploration opportunities in the deepwater Gulf of Mexico and the offshore Eastern Mediterranean and West Africa. We actively manage our portfolio with periodic divestments to “high grade” the portfolio. As a result of our continued exploration success, we are focused on the development of a significant portfolio of major projects in a number of key operating areas including, among others, Galapagos and Gunflint in the Gulf of Mexico, Tamar in Israel and Aseng and Belinda in West Africa. Our major development projects typically offer long life, sustained cash flows after investment and attractive financial returns. We maintain a balanced portfolio between US and international locations which ledassets and a balanced geographic and political risk profile.  We also maintain a diversity of production mix between oil, US natural gas production and international gas.
Financial and Operating Results 2009 was a challenging year in the energy industry due to significant new discoveries. We fundedthe prolonged recession, constraint in the credit markets, and commodity price volatility. These conditions resulted in our capital program primarily withreduced net income and cash flows from operationsoperations. We reduced our capital spending program from our 2008 level as an outcome of the financial crisis. However, we were able to move forward on several major development projects as well as pursue additional exploration opportunities which resulted in important new discoveries, and increasedwe maintained our ending cash balance.strong balance sheet and ample liquidity levels.
 
Our 2009 financial results included the following:
 
 ·net loss of $131 million as compared with net income of $1.4 billion a 43% increase over 2007;for 2008;
·asset impairment charges of $604 million as compared with $294 million for 2008;
 ·$440110 million loss on commodity derivative instruments (including unrealized mark-to-market loss of $606 million) as compared with a $440 million gain on commodity derivative instruments;instruments (including unrealized mark-to-market gain of $522 million) for 2008;
 ·diluted loss per share of $0.75, as compared with diluted earnings per share of $7.58 a 39% increase over 2007;for 2008;
 ·cash flows provided by operating activities of $1.5 billion, as compared with $2.3 billion a 13% increase over 2007;in 2008;
 ·$294 million asset impairment charges;capital spending of $1.3 billion as compared with $2 billion in 2008;
 ·$38issuance of $1 billion in 10-year unsecured notes;
·reduction of $225 million write-downprincipal amount of receivabledebt;
·repatriation of $180 million of earnings from Semcrude, L.P.;foreign subsidiaries;
·revenues of $86 million related to deepwater Gulf of Mexico royalties refund and $11 million of associated interest income;
 ·year-end cash balance of $1 billion, as compared with $1.1 billion a $480 million increase overat the prior year endingend of 2008;
·total liquidity of $2.7 billion at December 31, 2009, consisting of year-end cash balance;balance plus funds available under credit facility; and
 ·year-end ratio of debt-to-book capital of 26%25% as compared with 28%26% at December 31, 2007.2008.
 

34


Significant operational highlights included the following:
 
Offshore United States
 ·significant oil discovery at Santa Cruz and sanction of the Gunflint prospectGalapagos oil development;
·successful new completion at the Swordfish field in the deepwater Gulf of Mexico;
 ·continued production growth in the Rocky Mountains area of our US operations;
·successful Benita oil appraisal well, offshore Equatorial Guinea;
·spud Deep Blue and Double Mountain exploration discoveries offshore Equatorial Guinea at Diega and Felicita;
·start-up of Phase 2 at the North Sea Dumbarton development;
·acquisition of producing properties in western Oklahoma;
·expanded acreage position onshore North America;
·successful appraisal of the South Raton discoverytest wells in the deepwater Gulf of Mexico;
 ·production start-up at the Raton gas developmentTiconderoga, in the deepwater Gulf of Mexico;Mexico, returned to full production of approximately 5,000 Boepd, net in August 2009 after being offline due to Hurricane Ike in 2008; and
 ·new Ticonderoga development wells brought online inaward of 22 lease blocks from the deepwaterCentral Gulf of Mexico;Mexico Lease Sale 208.
Onshore United States
·announced DJ Basin asset acquisition which will expand our largest onshore US property at Wattenberg;
·record Wattenberg field production of 269 MMcfepd, including liquid production of over 20 MBpd; and
·completion of our first horizontal East Texas Haynesville shale well with an initial thirty-day average production rate of over 11 MMcfpd, gross.
International
·sanctioned Aseng field oil development in Block I offshore Equatorial Guinea;
 ·successful high bidsexploration well and appraisal offshore Israel at Tamar, our largest discovery to date;
·
executed two letters of intent to sell natural gas from the Tamar field offshore Israel with expected gross revenues of over $10 billion;
·additional natural gas discovery offshore Israel at Dalit;
·first oil discovery on 15 deepwater Gulf of Mexico lease blocksBlock O offshore Equatorial Guinea at the Carmen prospect;
·realized record natural gas prices in the central Gulf of Mexico lease sale;Israel; and
 ·record annual natural gas productioncompleted field optimization efforts at the Dumbarton field and brought on line the first well at Lochranza in Israel of 139 MMcfpd.the North Sea.
 
In addition, in January 2009, we announced a very significant natural gas discoveryended the year with total proved reserves of 820 MMBoe as compared with 864 MMBoe at the Tamar prospect offshore Israel.end of 2008. See Proved Reserves discussion below.
 
Impact of and Our Responses to the Recession and Current Credit and Commodity Markets–The   Our business in 2009 was negatively impacted by the recession that began in 2008 and continues to impact the US and other world economies, are currentlyas well as by the constraint in a recession which could last well into 2009 and beyond. Additionally, the credit markets are experiencing significant volatility, and many financial institutions havevolatile commodity prices.  During late 2008 and 2009, we took initiatives to strengthen our liquidity concerns, prompting government intervention to mitigate pressure on the credit markets. Our primary exposurein response to the currentongoing uncertainty.  As a result of our actions, described below, we believe we are in a strong financial position with approximately $2.7 billion of liquidity, consisting of our cash plus funds available under our credit market crisis includesfacility, sufficient to position us to initiate execution of our revolving credit facility, cash investmentslong-term business strategy including development of our major projects and counterparty nonperformance risks.increased exploration activity.
 
Our revolvingDebt    In February 2009 we issued $1 billion of 8¼% senior notes due 2019 and used substantially all of the net proceeds to repay outstanding indebtedness under our credit facility.  
At December 31, 2009, $1.7 billion was available for borrowing under our credit facility. The credit facility is committed in the amount of $2.1 billion until December 2011, at which time it reduces to $1.8 billion. As of December 31, 2008, we had $494 million available credit under the facility. If not extended, the credit facility matures in December 2012. Should current credit market tightening be prolonged for several years,conditions continue, future extensions of our credit facility may contain terms that are less favorable than those of ourthe current credit facility. See Liquidity and Capital Resources below.
 
CurrentCash     We have over $1 billion in cash and cash equivalents invested in money market conditions also elevatefunds and short-term deposits with major financial institutions. During the concernfirst half of 2009, in response to the credit market crisis, we shortened the duration of our bank deposits and held over 50% of our cash investments,and cash equivalents in US Treasury securities. We maintained this investment posture well into the third quarter of 2009 before we started to reduce our US Treasury holdings in favor of reinvestment back into money market funds and time deposits with highly rated banks.  During first quarter 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes.
We monitor the creditworthiness of the banks and financial institutions with which total $1.1 billion,we invest and counterparty risksreview the securities underlying our investment accounts. However, we are unable to predict sudden changes in solvency of our financial institutions. In the event of a bank failure, we could incur a significant loss.
Counterparty Credit Risk   Counterparty risk related to our commodity derivative contracts and trade credit.  With regard tocredit also increased.  All of our cash investments, we invest in highly liquid, investment-grade securities, US Treasury securities and short-term deposits commodity derivative instruments are with major financial institutions.  In response to the credit market crisis, we have shortened the duration of our investment maturities and have increased our investments in US Treasury securities.

30

At December 31, 2008,Although our open commodity derivative instruments were in a net receivablepayable position with a fair value of $445 million. We have all of our commodity derivative instruments with major financial institutions.  Shouldat December 31, 2009, if one of these financial counterparties does not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and we could incur a loss.  
We sell our crude oil, natural gas and NGLs to a variety of purchasers.  Some of these parties are not as creditworthy as we are and may experience liquidity problems.  Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including from our largest international crude oil purchaser; however, we do not have all of our trade credit enhanced through guarantees or credit support.  Nonperformance by a trade creditor could result in losses. In third quarter 2008, we reduced the carrying value of a receivable from SemCrude, L.P., a crude oil purchaser, and recognized a pre-tax charge of $38 million for a probable loss. See Item 8. Financial Statements and Supplementary Data– Note 17 – Commitments and Contingencies.
 
Crude oil and natural gasCommodity Prices    Commodity prices are also volatile as evidenced bycontinue to be volatile. Prices declined significantly during the significant decline duringlast half of 2008 and into 2009. ContinuedDuring 2009, the commodities market strengthened, but our average realized prices for 2009 were significantly lower than average realized 2008 prices.  Lower commodity prices will reducereduced our cash flows from operations.operations as compared to prior years. To mitigate the impact of lower commodity prices on our cash flows, we have entered into crude oil and natural gas commodity contracts for 2009, 2010 and to a lesser extent, 2010.2011. See Item 8. Financial Statements and Supplementary Data—Data – Note 6 –6. Derivative Instruments and Hedging Activities.  Depending on the length of the currentIf we experience a “double-dip” recession, a short-lived recovery followed by another recession, commodity prices may stay depressed orcould decline further, thereby causing a prolonged downturn,again, which would further reduce our cash flows from operations.  This couldmay cause us to alter our business plans including reducingfurther reduction or delayingdelay in our exploration and development program spending andand/or implement other cost reduction and capital preservation initiatives.See 2010 Budget below.
 
In addition, the following events impacted our business in 2008:
35
 
AssetProperty Impairments–The significant decreases in crude oil and natural gas prices resulted in a reduction of the carrying values of certain of our oil and gas properties.  The commodity price decreases that began during the second half of 2008 required us to record asset impairment charges during fourth quarter 2008.  Further declines in natural gas prices during first quarter 2009 led us to review those properties that, at year-end 2008, were susceptible to impairment should commodity prices decline appreciably.  As a result of the depressed economic environment, coupled with a severe decreasethis review, we determined that additional properties were impaired as of March 31, 2009. We recorded additional impairment charges at December 31, 2009 due to price and/or performance issues. Future declines in commodity prices during the fourth quarter of 2008, we assessed the recoverabilitycould result in additional impairment of our oil and gas properties, and other investments. As a result of this analysis we determined that certain of ourlong-lived assets were impaired. In addition, during third quarter 2008, we initiated a process to sell our remaining operated non-core Gulf of Mexico shelf asset at Main Pass andor goodwill. We also recorded an impairment loss (based on anticipated proceeds less costsdue to sell). For 2008, total pre-tax (non-cash) asset impairment charges totaled $294 million.a dispute in Ecuador regarding our natural gas-to-power project. See Critical Accounting Policies – Impairment of Proved Oil and Gas Properties and Other Investments, and Impairment of Unproved Oil and Gas Properties. See also Item 8. Financial Statements and Supplementary Data—– Note 3–3. Asset Impairments and Note 4–Acquisitions and Divestitures–Main Pass Asset.Impairments.
 
Hurricanes GustavOperating Costs   We are closely monitoring costs and Ike – In September, Hurricanes Gustavhave implemented several cost savings initiatives, including continued reduction of well costs through drilling and Ike moved through the Gulfcompletion efficiencies and comprehensive review of Mexico. Inspection of our facilitiesoil and equipment indicated there was no major damage from the hurricanes, although damagegas operating costs.  We are also continuing to third party processingsee reductions in third-party drilling costs and pipeline facilities has slowed reinstatement of production from our Gulf of Mexico assets, including Lorienoperating supplies and Ticonderoga. Temporary shut-ins of production reduced volumes on average 7.2 MBoepd during third quarter 2008 and 9.0 MBoepd during fourth quarter 2008. Approximately 8.5 MBoepd of our Gulf of Mexico production remained shut-in at December 31, 2008. We expect production to resume during the first half of 2009, pending the successful resumption of pipeline and other non-operated facilities.services.
OPERATING OUTLOOK
 
Mid-continent Acquisition2010 Production   – In July 2008, we acquired producing properties in western Oklahoma for $292 million in cash. Properties acquired cover approximately 15,500 net acres and are currently producing a net 20 MMcfepd with approximately 70% natural gas and 30% liquids. We operate the assets with an average working interest of 83%.
Sale of Argentina Assets— In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The sale is subject to Argentine government approval, which has not been received. Accordingly, the gain on sale of approximately $24 million has been deferred. We are currently unable to predict when government approval will be obtained.
2009 OUTLOOK
We expect the mid-point of our 2009that we will have a modest increase in crude oil, natural gas and NGL production in 2010 as compared with 2009 as a result of the acquisition of additional US Rocky Mountain assets scheduled to be slightly above our 2008 results. Theclose first quarter 2010, and higher production in Israel and the North Sea. Our expected year-over-year change incrude oil, natural gas and NGL production isfor 2010 may be impacted by several factors including:
 
 ·the amountoverall level and timing of development capital expenditures;expenditures which, as discussed below, and dependent upon our drilling success, are expected to maintain our near-term production volumes;
·higher sales of natural gas from the Alba field in Equatorial Guinea;
·growth in demand for natural gas in Israel; and
·growing production from our Rocky Mountains assets, where we are continuing an active drilling program;
offset by
 ·natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-continent areas of our US operations.operations and in the North Sea;
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Factors potentially impacting our expected production profile include:
 ·overall levelvariations in sales volumes of natural gas from the Alba field in Equatorial Guinea related to potential downtime at the methanol, LPG and/or LNG plants;
·Israeli demand for electricity which affects demand for natural gas as fuel for power generation, market growth and competing deliveries of natural gas from Egypt;
·successful closing on purchase of additional US Rocky Mountain assets;
·variations in North Sea sales volumes due to potential FPSO downtime and timing of capital expenditures, as discussed below, which, dependent uponliftings;
·seasonal variations in rainfall in Ecuador that affect our drilling success, are expected to result in near-term production growth;natural gas-to-power project;
 ·potential hurricane-related volume curtailments in the deepwater Gulf of Mexico and Gulf Coast areas of our US operations as occurred with Hurricanes Gustav and Ike;
·the restoration of pipeline and facilities necessary to increase our Gulf of Mexico production;Ike in 2008;
 ·potential winter storm-related volume curtailments in the Northern region of our US operations;
 ·potential pipeline and processing facility capacity constraints in the Rocky MountainsMountain area of our US operations and timing of start up of a new interstate crude oil transportation pipeline system which will run from Weld County, Colorado to Cushing, Oklahoma;
·deliveries of Egyptian gas in Israel, which could lower our sales volumes;operations;
 ·potential downtime at the methanol, LPG and/or LNG plantsvolume curtailments in Equatorial Guinea;Ecuador due to unsettled economic and political environment;
 ·seasonal variations in rainfall in Ecuador that affect our natural gas-to-power project; andimpact of asset purchases;
 ·timing of significant project completion and initial production.production; and
·impact of sales of non-core operating assets.
 
20092010 Budget—Due to the uncertain economic and commodity price environment, we have designed a flexible   Our total capital spending program that will be responsive to conditions that develop during 2009.  Our preliminary base capitalinvestment program for 2009 will accommodate an investment level similar2010 is estimated at $2.5 billion, with 40% going toward major project investments, 20% for exploration activities, and the remaining 40% for ongoing maintenance and near-term development opportunities.  Approximately 55% of the total is to our original 2008 program which was $1.6 billion.  However, depending on commodity prices and other economic conditions we experiencebe spent in the first half of 2009, this base capital program may be adjusted up or down by approximately 10%US with the other 45% allocated to 15%.  international activities.
 
Approximately 40%Major project investments are expected to be about $1 billion, with the majority of capital directed toward the 2009 budget is committed to longer-term projects that will provide considerable production growth several yearsdevelopment of Galapagos in the future. The remainder is allocated toward maintaining and strengthening the existing property base.  Development spending will focus on our international and deepwater Gulf of Mexico, assets as well as certain higher returnAseng offshore Equatorial Guinea, and Tamar offshore Israel.  Approximately $500 million is slated for exploration activities, representing our largest ever annual exploration program.  This program includes participation in seven high-impact offshore wells in the deepwater Gulf of Mexico, Equatorial Guinea and the Mediterranean Sea.  The remainder of our budget is focused on liquid-rich and emerging opportunities onshore in the US.  The exploration budget will center on significant resource potentialUS, as well as near-term development projects in Israel, West Africathe North Sea and the deepwater Gulf of Mexico.  International expenditures are estimated to represent 30% of the total capital program.China.
 
The 2009Excluded from the capital budget does not includediscussed above is the impact$494 million we expect to pay for the DJ Basin asset acquisition scheduled to close in the first quarter 2010, as well as $235 million of possible asset purchases. non-cash capital expected to be accrued for the Aseng FPSO capital lease.
We expect that the 20092010 budget will be funded primarily from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing. We will evaluate the level of capital spending throughout the year based on drilling results, commodity prices, cash flows from operations and property acquisitions and divestitures.

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Exploration Program   We have significant remaining exploration potential, primarily in the deepwater Gulf of Mexico and offshore Equatorial Guinea and Israel, and are planning to increase our level of exploratory activity in 2010 over that of 2009. We are currently engaged in drilling operations at two significant test wells in the deepwater Gulf of Mexico, one at the Deep Blue prospect and the second at the Double Mountain prospect and plan to drill the Santiago exploratory well later in 2010. In addition, we are planning further exploratory drilling offshore Equatorial Guinea and another exploratory well offshore Israel, pending the outcome of a seismic program.
Exploratory activity, particularly offshore, is expensive and requires significant capital investment. We do not always encounter commercially productive reservoirs through our drilling operations and, as a result, could incur significant dry hole cost. Dry hole cost was particularly low in 2009 as compared with prior years, due to our unprecedented exploratory drilling success which resulted in new discoveries in Israel, Equatorial Guinea and the deepwater Gulf of Mexico. This level of exploratory success will be difficult to maintain. We are planning an active exploratory drilling program in 2010. As a result, dry hole cost could be significant.
Pending Asset Acquisition   On December 31, 2009, we entered into a definitive agreement to acquire substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for $494 million. We estimate total proved reserves to be 53 MMBoe, 45% of which are liquids and 80% within the liquid-rich Wattenberg field in the Northern region of our US operations. The acquisition will add approximately 10 MBoepd or 46 MMcf of natural gas and 2.5 MBbls of liquids to our daily production base. The acquisition is expected to close late in the first quarter 2010 and is subject to customary closing conditions. Funding is expected to be provided through our existing credit facility.
Major Development Project Inventory Our current inventory of major development projects includes the Aseng oil project and the Galapagos oil project, both of which have been sanctioned, as well as Tamar, Gunflint, the Belinda cycling project, Diega/Carmen and other potential West Africa gas projects.  These projects will require significant capital investments.  For example, total development costs for the Aseng oil project, excluding costs related to a leased FPSO, are estimated at $1.3 billion ($530 million for our share). Our share of the development costs for the Galapagos oil project is estimated at $360 million.
We expect to spend approximately $1 billion per year in 2010 and 2011 for major project development. We plan to fund these projects from cash flows from operations, cash on hand, and borrowings under our revolving credit facility and/or other financing such as a public debt offering. We expect first production to occur in 2011 when Galapagos comes on line, followed by Aseng and Tamar in 2012. Once these three projects begin producing, we expect to begin generating sufficient amounts of cash flow to self-fund the remaining discovered major projects investments.
As operator on the Aseng and Tamar development projects, we pay joint venture expenses and bill our nonoperating partners for their respective shares of joint venture costs. This increases our counterparty credit risk substantially. See Impact of Recession and Current Credit and Commodity Markets – Counterparty Credit Risk, above, and Item 1A. Risk Factors – Failure to effectively execute our major development projects could result in significant delays and/or cost over-runs, damage to our reputation, limitations on our growth and negative effects on our operating results. and We are exposed to counterparty credit risk as a result of our receivables, hedging transactions, and cash investments.
Growing Israel Natural Gas Realizations During third quarter 2009, we signed a new natural gas sales contract with our primary customer, IEC, under the terms of which they will purchase the majority of our remaining undedicated Mari-B field gas at prices expected to be significantly higher than what we have been receiving under the original contract. The actual price received is tied to a blend of liquids prices and a producer price index.  In addition, it was agreed that all sales from the Mari-B field going forward will be proportionately allocated between the two contracts regardless of the total volume sold. This is a major change from the past arrangement wherein only “excess” volumes above a threshold level received premium prices.
In addition, in fourth quarter 2009, we announced that we had signed an LOI to sell natural gas from the Tamar field, offshore Israel, to Dalia Power Energies (Dalia). Dalia, a privately-owned electricity company, has a license to build a natural gas-fired power plant in Israel with operations planned to commence in 2013. According to terms of the LOI, we and our partners will deliver natural gas volumes of approximately 200 Bcf to Dalia under a 17-year supply agreement. Total revenues for these volumes are estimated to be at least $1 billion. Sales volumes under the LOI may be increased to 700 Bcf depending upon the final size of the power plant and extent of operations. We also signed an LOI to sell natural gas from the Tamar field to IEC. IEC expects to purchase at least 95 Bcf of natural gas per year with the potential to procure significantly higher quantities for a period of 15 years beginning at the startup of Tamar.
Potential Asset Sale We maintain an ongoing portfolio optimization program which may result in the divestiture of non-core operating assets in order to maintain a balanced portfolio of high-quality, core properties. In 2009, we conducted a market test of our wholly-owned subsidiary Noble Energy (Europe) Limited, which holds our interests in the Netherlands and the UK, and received bids. However, we have not committed to a plan to sell these assets.
Current Conditions in Ecuador   The economic and political environment in Ecuador has become increasingly unsettled. See Item 1A. Risk Factors – Our operations and investment in Ecuador may be adversely affected by the country’s unsettled economic and political environment and Item 8. Financial Statements and Supplementary Data – Note 3. Asset Impairments.

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Climate Change   Climate change has become the subject of an important public policy debate. While climate change remains a complex issue, scientific research suggests that an increase in greenhouse gas emissions (GHGs) may pose a risk to society and the environment. The oil and natural gas exploration and production industry is a source of certain GHGs, namely carbon dioxide and methane, and future restrictions on the combustion of fossil fuels or the venting of natural gas could have a significant impact on our future operations. We are actively monitoring the following climate change related issues:
Impact of Legislation and Regulation   The commercial risk associated with the exploration and production of fossil fuels lies in the uncertainty of government-imposed climate change legislation, including cap and trade schemes, and regulations that may affect us, our suppliers, and our customers. The cost of meeting these requirements may have an adverse impact on our financial condition, results of operations and cash flows, and could reduce the demand for our products.
Climate change legislation and regulations have been adopted by many foreign countries and states in the US; however, legislation and regulations have not been enacted in all of the foreign countries where we operate or at the federal level in the US, although Congress and several states are considering adopting climate change legislation. The current state of development of many state and federal climate change regulatory initiatives in areas where we operate makes it difficult to predict with certainty the future impact on us, including accurately estimating the related compliance costs that we may incur.
Impact of International Accords The Kyoto Protocol to the United Nations Framework Convention on Climate Change went into effect in February 2005 and requires all industrialized nations that ratified the Protocol to reduce or limit greenhouse gas emissions to a specified level by 2012. The US has not ratified the Protocol. The US, Israel, and the European Union have participated in international discussions to develop a treaty or other agreement to require reductions in greenhouse gas emissions after 2012 and have indicated that they wish to associate themselves with the Copenhagen Accord, which includes a non-binding commitment to reduce greenhouse gas emissions.
While no specific new international climate change accord has been adopted that would affect our operating locations, the current state of development of many initiatives makes it difficult to assess the timing or effect of any pending discussions of future accords or predict with certainty the future costs that we may incur in order to comply with future international treaties or regulations.
Indirect Consequences of Regulation or Business Trends    We believe there are both risks and opportunities arising from the global response to climate change. See Items 1 and 2. Business and Properties – Regulation and the following risk factors listed in Item 1A. Risk Factors –
·We are subject to various governmental regulations and environmental risks that may cause us to incur substantial costs;
·
Increased regulation of business practices could result in increased operating costs; and
·The adoption of pending climate change legislation could result in increased operating costs, create delays in our obtaining air pollution permits for new or modified facilities, and reduce demand for the crude oil and natural gas we produce.
In terms of opportunities, the regulation of GHGs and introduction of formal technology incentives, such as enhanced oil recovery, carbon sequestration and low carbon fuel standards, could benefit us in a variety of ways.
First, more than 60% of our 2009 production was natural gas. Climate change legislation could reduce the demand for the crude oil and natural gas we produce.  At the same time, the burning of natural gas produces lower levels of emissions than other readily available fossil fuels such as oil and coal. Therefore, the use of natural gas may increase should the use of other fossil fuels decrease due to climate change regulation. Furthermore, should renewable resources, such as wind or solar power become more prevalent, natural gas-fired electric plants may provide an alternative backup to maintain consistent electricity supply.
Second, market-based incentives for the capture and storage of carbon dioxide in underground reservoirs, particularly in oil and natural gas reservoirs, could benefit us through the potential to obtain GHG allowances or offsets from or government incentives for the sequestration of carbon dioxide.
Finally, should states adopt low-carbon fuel standards, natural gas may prove to be a more attractive transportation fuel. This may increase the market demand for natural gas.
Physical Impacts of Climate Change on our Costs and Operations     There has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornados and snow or ice storms, as well as rising sea levels. Extreme weather conditions increase our costs, and damage resulting from extreme weather may not be fully insured. However, the extent to which climate change may lead to increased storm or weather hazards affecting our operations, particularly our offshore operations, is difficult to identify at this time. See Item 1A. Risk Factors – We may not have enough insurance to cover all of the risks we face, which could result in significant financial exposure.

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RESULTS OF OPERATIONS
 
Net IncomeSelected financial information is as follows:
 
Net
  Year Ended December 31, 
  2009 2008 2007 
(millions, except per share)       
Total Revenues $2,313 $3,901 $3,272 
Total Operating Expenses  2,371  2,266  1,777 
Operating Income (Loss)
  (58) 1,635  1,495 
Total Other (Income) Expense  206  (426) 127 
Income (Loss) Before Income Taxes  (264) 2,061  1,368 
Net Income (Loss)  (131) 1,350  944 
Earnings (Loss) Per Share          
Basic $(0.75)$7.83 $5.52 
Diluted  (0.75) 7.58  5.45 
Factors contributing to the decrease in net income forin 2009 as compared with 2008 was $1.4 billion, a 43% increase over 2007. included the following:
·$1.6 billion decrease in total revenues due primarily to lower commodity prices;
·$110 million mark-to-market loss on derivative instruments;
·$604 million asset impairment charges; and
·$25 million increase in DD&A expense;
offset by:
·
$86 million refund of deepwater Gulf of Mexico royalties plus interest of $11 million;
·$69 million decrease in total production costs; and
·$73 million decrease in exploration expense.
Factors contributing to the increase in net income in 2008 as compared with 2007 included the following:
 
 ·$629 million or 19%, increase in total revenues due primarily to higher commodity prices; and
 ·$440 million mark-to-market gain on derivative instruments;
offset by:
 ·$294 million asset impairment of assets;charges;
 ·$106 million increase in total production costs;
 ·$55 million increase in DD&A expense; and
 ·$38 million write-down of receivable from Semcrude, L.P.
 
Net income for 2007 was $944 million, a 39% increase over 2006. Factors contributing to the increase in net income from 2006 to 2007 included the following:
·$332 million, or 11%, increase in total revenues, due primarily to higher average realized commodity prices and an increase in income from equity method investees; and
·$394 million decrease in loss on derivative instruments;
offset by:
·$208 million decrease in gains from asset sales;
·$103 million increase in DD&A expense;
·$51 million loss on involuntary conversion expense; and
·$51 million increase in oil and gas exploration expense.

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Discontinuance of Cash Flow Hedge Accounting    – Effective January 1, 2008, we discontinued cash flow hedge accounting on all existing commodity contracts (or “commodity derivative instruments”). We voluntarily made this change to provide greater flexibilitysimplify the accounting for our commodity hedge program as well as to add more transparency in related disclosures for the benefit of our use of derivative instruments.investors.  From January 1, 2008 forward, we recognize all gains and losses on such instruments in earnings in the period in which they occur. The discontinuance of cash flow hedge accounting for commodity derivative instruments has no impact on our net assets or cash flows and previously reported amounts have not been adjusted. However, the use of mark-to-market accounting adds volatility to our net income.
 
NetDerivative gains and losses included in net income for 2008 included a $440 million gain on commodity derivative instruments, of which $82 million was ainclude both pre-tax realized loss,gains and $522 million was alosses and pre-tax, unrealized, non-cash gaingains or losses which are due to the change in the mark-to-market value of our commodity contracts related to production in future periods. Unrealized mark-to-market gains or losses recognized in the current period will be realized in the future when they are cash settled in the month that the related production occurs. The amount of gain or loss actually realized may be more or less than the amount of unrealized mark-to-market gain or loss previously reported. See Item 8. Financial Statements and Supplementary Data – Note 6. Derivative Instruments and Hedging Activities.
 

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Oil, Gas and NGL Sales
 
RevenuesAn analysis of revenues from sales of commodities werecrude oil, natural gas and NGLs is as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Crude oil and condensate sales $2,101  $1,694  $1,489 
Natural gas sales  1,375   1,272   1,212 
NGL sales (1)
  175   -   - 
Total $3,651  $2,966  $2,701 
  Crude Oil and Condensate Natural Gas 
NGLs (1)
 Total 
(millions)         
2007 Sales Revenues $1,694 $1,272 $- $2,966 
Changes due to             
Increase (Decrease) in Sales Volumes  (152) 165  175  188 
Increase in Sales Prices Before Hedging  701  73  -  774 
Change in Amounts Reclassified from AOCL  (142) (135) -  (277)
2008 Sales Revenues  2,101  1,375  175  3,651 
Changes due to             
Increase (Decrease) in Sales Volumes  (232) 15  -  (217)
Decrease in Sales Prices Before Hedging  (915) (655) (77) (1,647)
Change in Amounts Reclassified from AOCL  307  (34) -  273 
2009 Sales Revenues $1,261 $701 $98 $2,060 
 
(1)For 2007, and 2006, US NGL sales volumes were included with natural gas volumes.  Effective in 2008, we began reporting US NGLs separately, which has lowered the comparative natural gas sales revenues from 2007 to 2008.2008 and 2009.
 

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Average daily sales volumes and average realized sales prices were as follows:
 
 Sales Volumes  Average Realized Sales Prices  Sales Volumes Average Realized Sales Prices 
 Crude Oil & Natural    Crude Oil & Natural    Crude Oil & Condensate (MBpd) Natural Gas (MMcfpd) 
NGLs
(MBpd) (1)
 Total (Boepd) 
Crude Oil & Condensate
(Per Bbl)
 
Natural Gas
(Per Mcf)
 NGLs (Per Bbl) 
 Condensate 
Gas (1)
 
NGLs (1)
  Condensate 
Gas (1)
 
NGLs (1)
 
 (MBopd) (MMcfpd) (MBpd)  (Per Bbl) (Per Mcf) (Per Bbl) 
Year Ended December 31, 2009               
United States (2)
  37  397  10  113 $55.19 $3.61 $27.96 
Equatorial Guinea (3)
  14  239  -  54  55.94  0.27  - 
Israel  -  114  -  19  -  3.47  - 
North Sea  7  5  -  8  59.51  5.75  - 
Ecuador (4)
  -  26  -  4  -  -  - 
China  4  -  -  4  54.40  -  - 
Total Consolidated Operations  62  781  10  202  55.76  2.54  27.96 
Equity Investees (5)
  2  -  6  8  59.51  -  36.03 
Total  64  781  16  210 $55.87 $2.54 $31.20 
Year Ended December 31, 2008                                    
United States (2)
  40  395  9  $75.53 $8.12 $50.15   40  395  9  116 $75.53 $8.12 $50.15 
West Africa (3)
  15  206  -   88.95  0.27  - 
Equatorial Guinea (3)
  15  206  -  49  88.95  0.27  - 
Israel  -  139  -  23  -  3.10  - 
North Sea  10  5  -   100.56  10.54  -   10  5  -  11  100.56  10.54  - 
Israel  -  139  -   -  3.10  - 
Ecuador (4)
  -  22  -   -  -  -   -  22  -  4  -  -  - 
Other International  4  -  -   82.66  -  - 
China  4  -  -  4  82.66  -  - 
Total Consolidated Operations  69  767  9   82.60  5.04  50.15   69  767  9  207  82.60  5.04  50.15 
Equity Investees (5)
  2  -  6   96.77  -  58.81   2  -  6  8  96.77  -  58.81 
Total  71  767  15  $82.96 $5.04 $53.45   71  767  15  215 $82.96 $5.04 $53.45 
Year Ended December 31, 2007                                          
United States (2)
  42  412  -  $53.22 $7.51 $-   42  412  -  111 $53.22 $7.51 $- 
West Africa (3)
  15  132  -   71.27  0.29  - 
Equatorial Guinea (3)
  15  132  -  37  71.27  0.29  - 
Israel  -  111  -  18  -  2.79  - 
North Sea  13  6  -   76.47  6.54  -   13  6  -  14  76.47  6.54  - 
Israel  -  111  -   -  2.79  - 
Ecuador (4)
  -  26  -   -  -  -   -  26  -  4  -  -  - 
Other International  7  -  -   53.69  -  - 
China  4  -  -  4  58.79  -  - 
Argentina  3  -  -  3  46.79  -  - 
Total Consolidated Operations  77  687  -   60.61  5.26  -   77  687  -  191  60.61  5.26  - 
Equity Investees (5)
  2  -  6   74.87  -  48.87   2  -  6  8  74.87  -  48.87 
Total  79  687  6  $60.94 $5.26 $48.87   79  687  6  199 $60.94 $5.26 $48.87 
                    
Year Ended December 31, 2006                    
United States (2)
  46  452  -  $50.68 $6.61 $- 
West Africa (3)
  18  45  -   62.51  0.37  - 
North Sea  4  8  -   67.43  8.00  - 
Israel  -  93  -   -  2.72  - 
Ecuador (4)
  -  25  -   -  -  - 
Other International  7  -  -   52.05  -  - 
Total Consolidated Operations  75  623  -   54.47  5.55  - 
Equity Investees (5)
  2  -  6   66.60  -  40.10 
Total  77  623  6  $54.75 $5.55 $40.10 
 
(1)For 2007 and 2006, US NGL sales volumes were included with natural gas volumes. Effective in 2008, we began reporting US NGLs separately, which has lowered the comparative natural gas sales volumes from 2007 to 2008.2008 and 2009. For 2007, US NGL sales volumes were included with natural gas volumes.
(2)Average realized crude oil and condensate prices reflect reductions of $2.13 per Bbl for 2009, $22.06 per Bbl for 2008, and $13.68 per Bbl for 2007 and $11.41 per Bbl for 2006 from hedging activities. Average realized natural gas prices reflect increases of $0.23 per Mcf for 2008 and $1.12 per Mcf for 2007 and a reduction of $0.25 per Mcf for 2006 from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis. The price increases and reductions resulted from hedge gains and losses that had been previously deferred in accumulated other comprehensive income or loss (AOCL).
(3)Average realized crude oil and condensate prices reflect reductions of $5.57 per Bbl for 2009, $7.59 per Bbl for 2008 and $2.19 per Bbl for 2007 from hedging activities.  The price reductions resulted from hedge losses that had been previously deferred in AOCL. We did not hedge West Africa crude oil sales in 2006. Natural gas from the Alba field in Equatorial Guinea is under contract for $0.25 per MMBtu to a methanol plant, an LPG plant and an LNG plant. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.  Natural gas volumes sold to the LNG plant totaled 163 MMcfpd in 2008 and 78 MMcfpd in 2007. The natural gas sold to the LNG and methanol plants has a lower Btu content than the natural gas sold to the LPG plant. As a result of the increase in natural gas volumes sold to the LNG plant to 2008, the average price received on an Mcf basis is lower.
(4)The natural gas-to-power project in Ecuador is 100% owned by our subsidiaries and intercompany natural gas sales are eliminated for accounting purposes. Electricity sales are included in other revenues. See Electricity Sales and Expense below.
(5)Volumes represent sales of condensate and LPG from the Alba plantPlant in Equatorial Guinea. See Income from Equity Method Investees below.
 

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Crude oil and condensate sales volumes in the table above may differ from actual production volumes due to the timing of liquid hydrocarbon tanker liftings. Crude oil and condensate production volumes were as follows:
  Year Ended December 31, 
  2008 2007 2006 
  (MBopd) 
United States  40  42  46 
West Africa  14  15  17 
North Sea  10  13  4 
Other International  4  7  8 
Total Consolidated Operations  68  77  75 
Equity Investees  2  2  2 
Total  70  79  77 

If the realized gains and losses on commodity derivative instruments, which are included in (gain) loss on commodity derivative instruments in our consolidated statements of operations, had been included in oil and gas revenues, the effect on average realized prices would have been as follows:

  
Year Ended December 31,2008 (1)
 
  Crude Oil &   Natural
  CondensateGas
  (Per Bbl)(Per Mcf) 
United States $71.68  $8.05 
West Africa  85.98   0.27 
Total Consolidated Operations  79.75   5.00 
Total  80.19   5.00 
(1)In 2007 and 2006 we applied cash flow hedge accounting.
  Commodity Price Increase (Decrease) 
  Crude Oil & Condensate Natural Gas Crude Oil & Condensate Natural Gas 
  2009 2008 
  (Per Bbl) (Per Mcf) (Per Bbl) (Per Mcf) 
Year Ended December 31,         
United States $12.26 $1.73 $(3.85)$(0.07)
Equatorial Guinea  15.36  -  (2.97) - 
Total Consolidated Operations  10.86  0.91  (2.85) (0.04)
Total  10.55  0.91  (2.77) (0.04)
 
Crude Oil and Condensate Sales
 
2009 Compared with 2008    Crude oil sales decreased by a net $840 million, or 40%, in 2009 as compared with 2008. The decrease was primarily due to a 32% decline in consolidated average realized prices due to the decreased demand for oil. In the US, crude oil sales decreased by $359 million primarily due to lower average realized prices. US crude oil sales were also impacted by a 7% decline in sales volumes due to natural field decline in the deepwater Gulf of Mexico and Gulf Coast area and the shut-in of Ticonderoga in the deepwater Gulf of Mexico until August 2009 after being offline due to Hurricane Ike in 2008. This decline was offset by increased production from the Wattenberg field in the northern region of our US operations due to ongoing development activity. Internationally, West Africa crude oil sales decreased by $192 million primarily due to lower average realized prices, plus a 4% decrease in production due to timing of liftings. In the North Sea, crude oil sales decreased by $247 million. Although the average realized North Sea oil price was significantly less than in 2008, the decline in sales was primarily driven by a 38% decline in sales volumes due to natural field decline and downtime beginning in mid-August at the Dumbarton field due to FPSO repairs. Crude oil sales in China decreased $42 million due to lower average realized prices.
2008 Compared with 2007   —CrudeCrude oil sales increased by a net $407 million, or 24%24%, in 2008 as compared with 2007. The increase was affected by both volume and price changes. In the US, crude oil sales increased by $286 million due to higher average realized prices. Sales volumes declined due to hurricane-related production shut-ins in the deepwater Gulf of Mexico from Hurricanes Gustav and Ike and declining production in the Gulf Coast onshore and Mid-continent areas of our US operations, offset by growth in the Rocky MountainsMountain area of our US operations.
Internationally, West Africa crude oil sales increased by $88 million due to higher average realized prices. North Sea crude oil sales increased by $39 million due to higher average realized prices, while sales volumes were affected by natural field decline. Other international crude oil sales decreased by $6 million primarily due to natural field decline in China.
Fourth quarter 2008 crude oil sales were significantly impacted by declining prices. Our average realized crude oil prices were $33.16 per Bbl for the US and $43.80 per Bbl for total consolidated operations for fourth quarter 2008.
 
2007 Compared with 2006—Crude oil sales increased a net $205 million, or 14%,Hedging Gains (Losses) Included in 2007 as compared with 2006. The increase was affected by both volume and price changes. In the US, crude oil sales declined by $25 million from the previous year. Deepwater Gulf of Mexico volumes were lower due to well performance, third-party facility restrictions and storm-related shut-ins. The Gulf Coast onshore area had lower production due to natural field decline, and a loss of production from the sale of our significant Gulf of Mexico shelf properties in 2006. Northern region production was negatively impacted by severe winter weather in the Rocky Mountains in the first and fourth quarters of 2007. However, development activity in the Wattenberg field, as well as a full year of production from U.S. Exploration properties acquired in 2006, resulted in increased production in our Northern region. The overall US volume decline was partially offset by higher average realized prices.Revenues    


Internationally, West Africa crude oil sales declined by $15 million from the previous year. Volumes declined due to increased downtime and lower condensate yields in Equatorial Guinea, but the decline was offset by substantially higher average realized crude oil prices. In January 2007, production began at the Dumbarton development in the North Sea, and, as a result, crude oil production was more than triple that of the prior year. North Sea crude oil sales increased $257 million over 2006 due to the increased volumes and, to a lesser extent, higher average realized prices. Other international crude oil sales declined $12 million. China experienced lower volumes due to facility downtime and natural field decline.
Crude oil sales include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007. Amounts included decreases of $58 million in 2009, $365 million in 2008, and $223 million in 2007, and $191 million in 2006.2007.  See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
Natural Gas Sales
 
2009 Compared with 2008     Natural gas sales decreased by a net $674 million, or 49%, in 2009 as compared with 2008. The decrease was primarily due to a 50% decline in consolidated average realized prices due to the decreased demand for natural gas. In the US, natural gas sales decreased by $653 million due to lower average realized prices. Overall, sales volumes remained about the same year to year. Increased production from the Wattenberg, Piceance and Western Oklahoma areas of our US operations were offset by natural field decline in the deepwater Gulf of Mexico, Gulf Coast and Mid-continent areas. Internationally, West Africa natural gas sales increased $3 million due to an increase in sales volumes. In Israel, natural gas sales decreased by $13 million. As a result of the new natural gas sales contract, discussed above, average realized prices in Israel increased. However, sales volumes declined 18% due to customer power plant downtime, warmer than normal winter weather conditions, and competing natural gas sales from Egypt. North Sea natural gas revenues decreased by $11 million primarily due to lower average realized prices.
2008 Compared with 2007—Natural gas sales increased by a net $103 million, or 8%, in 2008 as compared with 2007. The increase was affected by both volume and price changes. In the US, natural gas sales increased by $44 million primarily due to higher commodity prices despite lower sales volumes. Lower volumes were the result of several factors including hurricane-related production shut-ins in the deepwater Gulf of Mexico from Hurricanes Gustav and Ike, reduction for shrink gas associated with the natural gas liquids now being reported separately, and declining production in the Gulf Coast onshore and Mid-continent areas of our US operations. The volume decline was offset by a successful drilling program in the Piceance basin along with less severe winter weather in the Rocky MountainsMountain area of our US operations.
Internationally, West Africa gas sales increased by $6 million from the previous year. Natural gas volumes were higher due to increased sales of natural gas from the Alba field in Equatorial Guinea; however, the effect of higher production was somewhat offset by lower average realized gas prices. In the North Sea, sales increased $6 million primarily due to higher average realized prices. In Israel, natural gas sales increasedby $44 million due to record sales volumes, which included the commencement of sales to the IEC power plant at Gezer, and higher average realized prices.
Fourth quarter 2008 natural gas sales were significantly impacted by declining prices. Our average realized natural gas prices were $5.30 per Mcf for the US and $3.62 per Mcf for total consolidated operations for fourth quarter 2008.
2007 Compared with 2006—Natural gas sales increased a net $60 million, or 5%, in 2007 as compared with 2006. The increase was affected by both volume and price changes. In the US, natural gas sales increased $40 million from the previous year despite lower sales volumes. Deepwater Gulf of Mexico volumes were slightly higher than 2006, while development activity in the Piceance basin and a full year of production from U.S. Exploration properties acquired in 2006 resulted in increased production in the Northern region. However, the Gulf Coast onshore area had lower production due to natural field decline, and there was a loss of production due to the sale of our significant Gulf of Mexico shelf properties in 2006. The Northern region also experienced a temporary decline in production due to third party processing downtime and inclement weather. The net production decrease was more than offset by a 14% increase in average realized natural gas prices.
Internationally, West Africa natural gas sales increased $8 million from the previous year. Natural gas volumes were higher due to increased sales of natural gas from the Alba field in Equatorial Guinea; however, the effect of higher production was somewhat offset by lower average realized gas prices. In the North Sea, natural gas production decreased 23% as compared with the prior yearsales increased by $6 million primarily due to natural field decline. Lower production, combined with lowerhigher average realized prices, resulted in a $9 million decrease in North Sea natural gas sales. In Israel, natural gas sales increased $21 million due to record sales volumes. There was a full yearprices.


 
Hedging Gains (Losses) Included in Revenues   Natural gas revenues include amounts reclassified from AOCL related to commodity derivative instruments which were accounted for as cash flow hedges through December 31, 2007.  Amounts included increases of $34 million in 2008 and $169 million in 2007, and a decrease of $41 million2007.  The impact was de minimis in 2006.2009. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 


NGL Sales
2009 Compared with 2008     NGL sales decreased by $77 million due to the decrease in average realized prices.
 
Effective in 2008, we began reporting US NGL sales separately. This has lowered the comparative natural gas sales volumes and revenues from 2007 to 2008. Most of our US NGL production is from the Wattenberg field and deepwater Gulf of Mexico.
 
Income from Equity Method Investees
 
We have a 45% interest in AMPCO, which owns and operates a methanol plant and related facilities. We also have a 28% interest in Alba Plant, which owns and operates an LPG processing plant. The plants and related facilities are located in Equatorial Guinea. We account for investments in entities that we do not control but over which we exert significant influence using the equity method of accounting.
 
Our share of operations of equity method investees was as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
Net income (in millions, except as noted) 
AMPCO and affiliates $56  $83  $38 
Alba Plant  118   128   101 
Distributions/dividends            
AMPCO and affiliates  65   97   37 
Alba Plant  156   132   151 
Sales volumes            
Methanol (MMgal) (1)
  119   161   110 
Condensate (MBopd)  2   2   2 
LPG (MBpd)  6   6   6 
Production volumes            
Methanol (MMgal) (1)
  116   163   109 
Condensate (MBopd)  2   2   2 
LPG (MBpd)  6   6   6 
Average realized prices            
Methanol (per gallon) $1.25  $1.09  $0.90 
Condensate (per Bbl)  96.77   74.87   66.60 
LPG (per Bbl)  58.81   48.87   40.10 
(1)The variance between methanol production and sales volumes is attributable to management’s decision to increase or decrease inventory.
  Year Ended December 31, 
  2009 2008 2007 
Net Income (in millions)       
AMPCO and Affiliates $18 $56 $83 
Alba Plant  66  118  128 
Dividends (in millions)          
AMPCO and Affiliates  29  65  97 
Alba Plant  63  156  132 
Sales Volumes          
Methanol (MMgal)  145  119  161 
Condensate (MBopd)  2  2  2 
LPG (MBpd)  6  6  6 
Average Realized Prices          
Methanol (per gallon) $0.60 $1.25 $1.09 
Condensate (per Bbl)  59.51  96.77  74.87 
LPG (per Bbl)  36.03  58.81  48.87 
 
AMPCO and Affiliates —  Net income from AMPCO and affiliates decreased by $38 million, or 68%, in 2009 as compared with 2008 due to the significant decrease in the average realized price for methanol. The price decrease is a result of an oversupply of methanol and the impact of the economic slowdown. While average realized prices were down for the year, there was a significant increase in methanol prices during fourth quarter 2009. Methanol sales volumes increased as there was minimal down time for repairs as compared with 2008.
Net income from AMPCO and affiliates decreased by $27 million, or 33%, in 2008 as compared with 2007 due to decreases in methanol sales volumes that resulted from 95 days of down time for compressor and other equipment repair and maintenance. The decreases in methanol sales volumes were offset by higher average realized methanol prices.
Alba Plant   Net income from Alba Plant decreased by $52 million, or 44%, in 2009 as compared with 2008 due to significant decreases in average realized prices for condensate and LPG. The price decrease is a result of decreases in crude oil prices and the impact of the economic slowdown. While average realized prices were down for the year, there was a significant increase in condensate and LPG prices during fourth quarter 2009.
 
Net income from AMPCO and affiliates increased substantially in 2007 as compared with 2006 due to increases in methanol sales volumes and average realized methanol prices. The increase in methanol sales volumes was due to a 57-day shutdown of methanol production for the plant turnaround that occurred during May and June 2006 followed by 35 days of compressor repairs.
Alba Plant—Net income from Alba Plant decreased by $10 million, or 8%, in 2008 as compared with 2007 primarily due to the expiration of the Alba Plant tax holiday, offset by higher average realized condensate and LPG prices. Net income from Alba Plant increased $27 million, or 27%, in 2007 as compared with 2006 due to increases in average realized condensate and LPG prices.
 
Our operating cash flows include dividends received from Alba Plant

Other Revenues
 
Refund of Deepwater Gulf of Mexico Royalties    We have recorded a refund of $86 million attributable to royalties that we previously paid on production of approximately 900 MBbls of crude oil and 3,000 MMcf of natural gas that was produced from January 1, 2003 through July 31, 2009 in the deepwater Gulf of Mexico. We have requested a refund from the MMS and anticipate receiving the monies in early 2010. Interest of $11 million related to the refund has been recorded in interest income. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.
Other   Other revenues include electricity sales and gathering, marketing and processing revenues. See Electricity Sales and Expense below. See also Item 8. Financial Statements - and Supplementary Data – Note 2 -2. Summary of Significant Accounting Policies.
 


Costs and Expenses
 
Production Costs—Production costs were as follows:
 
     United  West  North     Other Int'l/ 
  Total  States  Africa  Sea  Israel  
Corporate (1)
 
  (in millions) 
Year Ended December 31, 2008                  
Oil and gas operating costs (2)
 $333  $222  $39  $50  $9  $13 
Workover and repair expense  38   35   -   3   -   - 
Lease operating expense  371   257   39   53   9   13 
Production and ad valorem taxes  166   135   -   -   -   31 
Transportation expense  57   49   -   7   -   1 
Total production costs $594  $441  $39  $60  $9  $45 
Year Ended December 31, 2007                        
Oil and gas operating costs (2)
 $299  $190  $39  $38  $8  $24 
Workover and repair expense  23   23   -   - �� -   - 
Lease operating expense  322   213   39   38   8   24 
Production and ad valorem taxes  114   91   -       -   23 
Transportation expense  52   40   -   11   -   1 
Total production costs $488  $344  $39  $49  $8  $48 
Year Ended December 31, 2006                        
Oil and gas operating costs (2)
 $270  $205  $27  $12  $9  $17 
Workover and repair expense  47   47   -   -   -   - 
Lease operating expense  317   252   27   12   9   17 
Production and ad valorem taxes  109   86   -   -   -   23 
Transportation expense  29   21   -   7   -   1 
Total production costs $455  $359  $27  $19  $9  $41 
  Total per BOE Total United States West Africa Eastern Mediter-ranean North Sea 
Other Int'l (1)
 
(millions, except per unit)               
Year Ended December 31, 2009               
Lease Operating Expense (2)
 $5.05 $372 $258 $45 $9 $43 $17 
Production and Ad Valorem Taxes  1.28  94  81  -  -  -  13 
Transportation Expense  0.80  59  52  -  -  4  3 
Total Production Costs (3)
 $7.13 $525 $391 $45 $9 $47 $33 
Total Production Costs per BOE    $7.13 $9.51 $2.30 $1.36 $17.50 $10.27 
Year Ended December 31, 2008                      
Lease Operating Expense (2)
 $4.90 $371 $257 $39 $9 $53 $13 
Production and Ad Valorem Taxes  2.19  166  135  -  -  -  31 
Transportation Expense  0.75  57  49  -  -  7  1 
Total Production Costs (3)
 $7.84 $594 $441 $39 $9 $60 $45 
Total Production Costs per BOE    $7.84 $10.43 $2.17 $1.07 $14.30 $15.94 
Year Ended December 31, 2007                      
Lease Operating Expense (2)
 $4.62 $322 $213 $39 $8 $38 $24 
Production and Ad Valorem Taxes  1.63  114  91  -  -  -  23 
Transportation Expense  0.74  52  40  -  -  11  1 
Total Production Costs (3)
 $6.99 $488 $344 $39 $8 $49 $48 
Total Production Costs per BOE    $6.99 $8.49 $2.89 $1.14 $9.81 $12.06 
 
(1)Other international includes Ecuador, China and Argentina (through February 2008).
(2)OilLease operating expense includes oil and gas operating costs include labor,(labor, fuel, repairs, replacements, saltwater disposal and other related lifting costs) and workover and repair expense.
(3)Consolidated unit rates exclude sales volumes and costs and exclude depreciation of support equipment and facilities such as vehicles.attributable to equity method investees.
 
OilLease operating expense remained flat overall in 2009 as compared with 2008. In the US, we initiated cost savings initiatives which included reduced repair programs and gasa reduction of other discretionary spending in our onshore US operations, including a reduced workover program in the Northern region.  Lease operating costsexpense increased $34in West Africa due to higher contractor costs. Lease operating expense decreased in the North Sea due to lower sales volumes. A higher volume of crude oil was inventoried, resulting in a deferral of production cost.
Lease operating expense increased by $49 million, or 11%15%, in 2008 as compared with 2007. The increase is primarilywas the result of higher costs related to the continuing active drilling program in the Rocky Mountains and Mid-continent areas of our US operations and increased workover activity in the Piceance basin, Wattenberg field, and Mid-continent and Gulf Coast areas of our US operations. North Sea oil and gas operating costs increased due to expanded operations and higher costs at the Dumbarton development.
Oil  Costs were also driven up by industry inflation resulting from the high level of exploration and gas operating costs increased $29 million, or 11%,production activities in 2007 as compared with 2006. The increase was primarily the result of expanded operations in Equatorial Guinea and the North Sea.
Workover and repair expense increased $15 million, or 65%, in 2008 as compared with 2007. The increase was primarily due to increased workover activity in the Piceance basin, Wattenberg field, and Mid-continent and Gulf Coast areas of our US operations.
Workover and repair expense decreased $24 million, or 51%, in 2007 as compared with 2006. The decrease was primarily due to a reduction in hurricane-related repair expense, which totaled $30 million in 2006 and $1 million in 2007.2008.
 
Production and ad valorem tax expense decreased by $72 million, or 43%, in 2009 as compared with 2008 due to reduced proceeds from sales attributable to lower commodity prices in the US and China and the cessation of production due to the sale of our interest in Argentina in 2008. Production and ad valorem tax expense increased by $52 million, or 46%, in 2008 as compared with 2007 and increased $5 million, or 5%, in 2007 as compared with 2006. The increases were driven primarily bydue to higher commodity prices and also by an increase in volumes subject to such taxes, mainly in the Northern region of our US operations.
 
Transportation expense increased by $2 million, or 4%, in 2009 as compared with 2008 due to the start up of a new interstate crude oil transportation pipeline system used to market our Wattenberg production and offset by lower sales volumes in the North Sea. Transportation expense increased by $5 million, or 10%, in 2008 as compared with 2007. The increase was2007 due primarily to higher natural gas production in the Wattenberg field and increased production from the Swordfish development in the deepwater Gulf of Mexico.



Transportation expense increased $23 million, or 79%, in 2007 as compared with 2006. The increase was due primarily due to changes in the terms of certain sales contracts for Northern region production and increased production in the North Sea.
Selected expenses on a per BOE of sales volume basis were as follows:
  Year Ended December 31, 
  2008  2007  2006 
Oil and gas operating  costs $4.39  $4.29  $4.14 
Workover and repair expense  0.51   0.33   0.72 
Lease operating costs  4.90   4.62   4.86 
Production and ad valorem taxes  2.19   1.63   1.67 
Transportation expense  0.75   0.74   0.44 
Total production costs (1)
 $7.84  $6.99  $6.97 
(1)Consolidated unit rates exclude sales volumes and costs attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea that began late first quarter of 2007. The inclusion of these volumes reduced the unit rate by $1.19 per BOE for 2008 and $0.51 per BOE for 2007.
The unit rates of total production costs per BOE have been increasing year-over-year since 2006. decreased for 2009 as compared with 2008 primarily due to the decline in production and ad valorem taxes.
The increases areunit rate of total production costs per BOE increased for 2008 as compared with 2007 due to rising third-party costs, higher production taxes and increased workover activity in the Piceance basin, Wattenberg field, and Mid-continent and Gulf Coast areas of our US operations.
 
Oil and Gas Exploration Expense—Exploration expense was as follows:
 
     United  West  North     Other Int'l/ 
  Total  States  Africa  Sea  Israel  
Corporate (1)
 
  (in millions) 
Year Ended December 31, 2008                  
Dry hole expense $84  $42  $1  $8  $-  $33 
Seismic  57   50   -   4   3   - 
Staff expense  62   14   7   5   1   35 
Other  14   13   -   1   -   - 
Total exploration expense $217  $119  $8  $18  $4  $68 
Year Ended December 31, 2007                        
Dry hole expense $90  $50  $40  $-  $-  $- 
Seismic  65   55   1   8   1   - 
Staff expense  46   12   2   9   1   22 
Other  18   17   -   -   -   1 
Total exploration expense $219  $134  $43  $17  $2  $23 
Year Ended December 31, 2006                        
Dry hole expense $70  $66  $-  $4  $-  $- 
Seismic  38   29   4   1   -   4 
Staff expense  39   13   3   5   -   18 
Other  21   20   -   1   -   - 
Total exploration expense $168  $128  $7  $11  $-  $22 
  Total  United States  West Africa  Eastern Mediter-ranean  North Sea  
Other Int'l, Corporate (1)
 
(millions)                  
Year Ended December 31, 2009                  
Dry Hole Expense $11  $8  $3  $-  $-  $- 
Seismic  62   47   -   15   -   - 
Staff Expense  65   13   10   1   2   39 
Other  6   6   -   -   -   - 
Total Exploration Expense $144  $74  $13  $16  $2  $39 
Year Ended December 31, 2008                        
Dry Hole Expense $84  $42  $1  $-  $8  $33 
Seismic  57   50   -   3   4   - 
Staff Expense  62   14   7   1   5   35 
Other  14   13   -   -   1   - 
Total Exploration Expense $217  $119  $8  $4  $18  $68 
Year Ended December 31, 2007                        
Dry Hole Expense $90  $50  $40  $-  $-  $- 
Seismic  65   55   1   1   8   - 
Staff Expense  46   12   2   1   9   22 
Other  18   17   -   -   -   1 
Total Exploration Expense $219  $134  $43  $2  $17  $23 
(1)Other international includes Ecuador, China, Argentina (through February 2008), Suriname, Cyprus, and other international new ventures.
Exploration expense decreased by $73 million, or 34%, in 2009 as compared with 2008. The decrease was almost entirely related to the decrease in dry hole expense as a result of our recent exploration successes in the deepwater Gulf of Mexico, Israel and Equatorial Guinea. Dry hole expense in 2009 related primarily to an unsuccessful exploratory well drilled in the Northern region.
 
Exploration expense was flat in 2008 as compared with 2007. Dry hole expense in 2008 related to exploratory drilling in Suriname ($33 million),; the deepwater Gulf of Mexico ($35 million),; the North Sea ($8 million),; and other onshore US areas ($7 million).
Exploration expense increased $51 million, or 30%, in 2007 as compared with 2006. US dry hole expense decreased $16 million due to a reduction in the number of dry holes drilled in 2007.  Dry hole expense increased $40 million in West Africa and included amounts2007 related to a dry exploratory well in Equatorial Guinea and expense related to a secondary target of an explorationexploratory well in Cameroon. Seismic expense increased a net $27 million in 2007 as compared with 2006, primarily due to increases in US seismic expense incurred in support of the 2007 central Gulf of Mexico outer continental shelf sale. Staff expense increased a net $7 million primarily due to new venture activity.
 


Exploration expense included stock-based compensation expense of $9 million in 2009, $1 million in 2008 and $2 million in 2007 and $1 million in 2006.2007.
 
Depreciation, Depletion and Amortization Expense—Depreciation, depletion and amortization (DD&A) expense was as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
United States $646  $580  $552 
West Africa  34   25   24 
North Sea  55   81   9 
Israel  24   18   14 
Other international, corporate, and other  32   32   34 
Total DD&A expense (1)
 $791  $736  $633 
Unit rate of DD&A per BOE (2)
 $10.44  $10.55  $9.71 
  Year Ended December 31, 
  2009  2008  2007 
(millions, except unit rate)         
United States $689  $646  $580 
Equatorial Guinea  38   34   25 
Israel  20   24   18 
North Sea  34   55   81 
Other International, Corporate, and Other  35   32   32 
Total DD&A Expense (1)
 $816  $791  $736 
Unit Rate per BOE (2)
 $11.08  $10.44  $10.55 
 
(1)DD&A expense includes accretion of discount on asset retirement obligations of $14 million in 2009, $10 million in 2008, and $8 million in 2007, and $11 million in 2006.2007.
(2)
Consolidated unit rates exclude sales volumes and costs attributable to equity method investees.Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea that began late first quarter of 2007. The inclusion of these volumes reduced the unit rate by $1.29 per BOE for 2008 and $0.63 per BOE for 2007.


Total DD&A expense increased in 2009 as compared with 2008 due to higher production in the Wattenberg, Piceance and western Oklahoma areas of our US operations and ongoing capital spending in our US operations, offset by lower sales volumes in the North Sea.  In addition, fourth quarter 2009 DD&A was impacted by the change in the SEC’s pricing rules from the use of year-end prices to 12-month average prices, which resulted in negative reserves revisions at December 31, 2009.  This resulted in an increase in fourth quarter DD&A of approximately $16  million. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for effects of reserves revisions due to lower commodity prices at December 31, 2009.
 
Total DD&A expense increased in 2008 as compared with 2007 due to several factors including higher acquisition and/or development costs in the Wattenberg field and other Rocky Mountain and Mid-continentUS onshore areas, in the US, negative year-end reservereserves revisions in the US due to lower commodity prices, and higher natural gas sales volumes in Israel and West Africa, offset by declining production in the North Sea.
 
Total DD&A expense increasedThe increase in 2007the unit rate for 2009 as compared with 2006 primarily2008 was due to higher crude oil sales volumesthe change in the North Sea duemix of production, including a decrease in lower-cost volumes from Israel; ongoing capital spending in US onshore areas; and negative reserves revisions related to start-up of the Dumbarton development, higher natural gas sales volumes in Israel and West Africa and higher acquisition and/or development costs in the North Sea and in the Wattenberg field and deepwater Gulf of Mexico in the US.lower year-end 2009 commodity prices.
 
The decrease in the unit rate for 2008 as compared with 2007 iswas due to a change in the mix of production.  Increased production of lower-cost natural gas volumes from the Alba field in Equatorial Guinea and Israel were partially offset by increased production from areas with higher acquisition and/or development costs, (the Wattenberg field and other Rocky Mountain and Mid-continentsuch as US onshore areas, in the US) and negative year-end reservereserves revisions in the US due to lower commodity prices.
 
The increase in the unit rate for 2007 as compared with 2006 was primarily due to higher acquisition and development costs in the US and the North Sea Dumbarton development.
DD&A expense includes abandoned assets cost of $5 million in 2007 and $1 million in 2006. There was no abandoned asset cost in 2008.
General and Administrative Expense—General and administrative (G&A) expense was as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
G&A expense (in millions) $236  $206  $165 
Unit rate per BOE (1)
 $3.12  $2.96  $2.52 
  Year Ended December 31, 
  2009  2008  2007 
G&A Expense (in millions) $237  $236  $206 
Unit Rate per BOE (1)
 $3.22  $3.12  $2.96 
 
(1)Consolidated unit rates exclude sales volumes and costs attributable to equity method investees. Sales volumes include natural gas sales to an LNG plant in Equatorial Guinea that began late first quarter of 2007. The inclusion of these volumes reduced the unit rate by $0.47 per BOE for 2008 and $0.21 per BOE for 2007.
 
G&A expense remained flat in 2009 as compared with 2008.
G&A expense increased by $30 million, or 15%, in 2008 as compared with 2007.  Our increased activities requirerequired additional personnel, which has resulted in higher payroll costs. We have also increased our incentive compensation accruals.


G&A expense increased $41 million, or 25%, in 2007 as compared with 2006 due to higher salaries and wages, including incentive compensation programs, resulting from an increase in the number of employees and results exceeding targeted performance goals.
 
In addition, G&A expense is impacted by the amountnumber of stock-based awards, the market price of our common stock and price volatility, all of which result in a higher fair value of stock-based awards as calculated using the Black-Scholes-Merton option pricing model. See Item 8. Financial Statements and Supplementary Data – Note 13. Stock-based Compensation.  G&A included stock-based compensation expense includedof $36 million in G&A has been increasing since the adoption of SFAS No. 123(R), “Share-Based Payment” in 2006 combined with additional equity-based awards. Stock-based compensation expense included in G&A totaled2009, $38 million in 2008, and $25 million in 2007 and $11 million in 2006.
G&A also includes actuarially-computed net periodic benefit cost related to pension and other postretirement benefit plans of $17 million in 2008, $17 million in 2007, and $19 million in 2006.2007.
 
Asset ImpairmentsImpairment of Assetsexpense was as follows:—During 2008, we recorded total pre-tax (non-cash)
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Asset Impairments $604  $294  $4 
For information regarding asset impairment charges, of $294 million primarily due to lower commodity prices at year-end. We recorded impairments of $4 million in 2007 and $9 million in 2006, primarily related to downward reserve revisions on proved US oil and gas properties and/or adjustment of the carrying value of properties to their fair values. Seesee Critical Accounting Policies and Estimates – Impairment of Proved Oil and Gas Properties and Other Investments and Impairment of Unproved Oil and Gas Properties;Properties, below, and Item 8. Financial Statements – Note 3 –3.  Asset Impairments.
Gain on Sale of Assets—See Item 8. Financial Statements and Supplementary Data—Note 4—Acquisitions and Divestitures.
 
Other Operating Expense, Net –  Other operating expense, net was as follows:
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
 Other Operating (Income) Expense, Net $45  $134  $124 
Other operating expense, net includes gain on asset sales; electricity generation expense,expense; gathering, marketing and processing expense,expense; (gain) loss on involuntary conversion of assetsassets; settlement of legal proceedings; and other operating (income) expense, net. See Electricity Sales and Expense and (Gain) Loss on Involuntary Conversion below. See also Item 8. Financial Statements – Note 2 –2. Summary of Significant Accounting Policies and Policies.

46
Note 17Table of Contents – Commitments and Contingencies - Purchaser Bankruptcy for

Net Gain on Asset Sales    Net gain on asset sales includes a discussion$24 million gain on the sale of our interest in Argentina in 2008. Recognition of the SemCrude matter.gain on the sale was deferred until second quarter 2009 when the Argentine government approved the sale.
 
Electricity Sales—Sales and Expense   We have a 100% ownership interest in an integrated natural gas-to-power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies fuel to the Machala power plant. Electricity sales are included in other revenues and electricity generation expense is included in other operating expense, net in the consolidated statements of operations.
 
Operating data is as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions, except as noted) 
Electricity sales $56  $71  $72 
Electricity generation expense  57   57   59 
Operating income  (1)  14   13 
Power generation (GW)  749   912   866 
Average power price ($/Kwh) $0.074  $0.078  $0.083 
  Year Ended December 31, 
  2009  2008  2007 
(millions, except as noted)         
Electricity Sales $72  $56  $71 
Electricity Generation Expense  18   57   57 
Operating Income  54   (1)  14 
Power Generation (GW)  902   749   912 
Average Power Price ($/Kwh) $0.080  $0.074  $0.078 
 
The volume of natural gas produced and electric power generated in Ecuador are related to thermal electricity demand in Ecuador which typically declines at the onset of the rainy season. When Ecuador has sufficient rainfall to allow hydroelectric power producers to provide base load power, we provide electricity only to meet peak demand. As seasonal rains subside, we experience increasing demand for thermal electricity.
 
Electricity generation expense includes all operating and non-operating expenses associated with the plant, including DD&A expense and changes in the allowance for doubtful accounts of $11 million in 2008, $14 million in 2007, and $15 million in 2006.  Through December 31, 2008, we recorded an allowance for doubtful accounts of $57 million.accounts.  The allowance wasis necessary to cover potentially uncollectible balances related to the Ecuador power operations, as certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. As a result of pursuing various strategies to protect our interests, including international arbitration and litigation,In 2009, we reached a settlement in fourth quarter 2008. However, we have not yet received any funds related toreduced the settlement. We will reverse our allowance for doubtful accounts upon receipt of payment fromby $46 million and included the Ecuadorian government. If not receivedamount as a reduction in the near term, we may continue pursuing our arbitration claim and litigation.
Aselectricity generation expense as a result of amounts received related to a settlement. We charged additions to the depressed economic environment, coupled with a severe decreaseallowance of $14 million in commodity prices during the fourth quarter2009, $11 million in 2008, and $14 million in 2007. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.
At both December 31, 2009 and 2008, we assessed the recoverability of our Ecuador investment. As a result of this analysisthese analyses, we determined that our investment was impaired and recorded a pre-tax (non-cash) impairmentimpairments of $100 million and $70 million.million, respectively.  See Critical Accounting Policies and Estimates – Impairment of Proved Oil and Gas Properties and Other Investments and Item 8. Financial Statements – Note 3 –3.  Asset Impairments.
 


(Gain) Loss on Involuntary Conversion—Conversion  In 2009, we recorded a net gain of $9 million related to receipt of insurance claims for damage caused by Hurricanes Katrina and Rita. We recorded losses on involuntary conversion of $9 million in 2008 and $51 million in 2007 related to hurricane damage to our Gulf of Mexico Main Pass assets. The amounts are included in other operating expense, net in the consolidated statements of operations. See Item 8. Financial Statements and Supplementary Data—Data – Note 2—2. Summary of Significant Accounting Policies.
Other    Other operating expense, net includes reductions in the carrying value of a receivable from SemCrude, L.P., a crude oil purchaser. Reductions totaled $12 million in 2009 and $38 million in 2008.  See Item 8. Financial Statements and Supplementary Data – Note 17.  Commitments and Contingencies.
 
(Gain) Loss on Commodity Derivative Instruments—Instruments We recorded a gain of $440 million in 2008, a gain of $2 million in 2007, and a loss of $392 million in 2006 related toGain (loss) on commodity derivative instruments. instruments was as follows:
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
 (Gain) Loss on Commodity Derivative Instruments $110  $(440) $(2)
See Critical Accounting Policies and Estimates – Derivative Instruments and Hedging Activities, below, and Item 8. Financial Statements and Supplementary Data—Data – Note 6—5. Fair Value Measurements and Disclosures and Note 6. Derivative Instruments and Hedging Activities.
 


Interest Expense and Capitalized Interest—Interest expense and capitalized interest were as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Interest expense $102  $130  $130 
Capitalized interest  (33)  (17)  (13)
Interest expense, net $69  $ 113  $117 
  Year Ended December 31, 
  2009  2008  2007 
(millions, except per unit)         
Interest Expense $129  $102  $130 
Capitalized Interest  (45)  (33)  (17)
Interest Expense, Net $84  $69  $113 
Unit Rate, per BOE $1.13  $0.91  $1.56 
 
Interest expense increased in 2009 as compared with 2008. The increase primarily relates to our $1 billion 8¼% senior unsecured notes due March 1, 2019, which we issued on February 27, 2009. This increase was partially offset by a significant decrease in credit facility interest expense due to a decline in both the average outstanding balance and the average interest rate.
Interest expense decreased in 2008 as compared with 2007 due to declining interest rates applicable to our credit facility from 5.28% at December 31, 2007 to 0.80% at December 31, 2008, partially offset by a higher amount outstanding under our credit facility during 2008. See also Liquidity and Capital Resources – Financing Activities below.
 
Interest expense was flat in 2007 as compared with 2006. The rate of interest applicable to the credit facility declined from 5.69% at December 31, 2006 to 5.28% at December 31, 2007, while the balance outstanding increased slightly.
Interest is capitalized on exploration and development projects using an interest rate equivalent to the average rate paid on long-term debt. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. The majority of the capitalized interest is related to long lead-time projects in West Africa, the deepwater Gulf of Mexico and Israel in 2009; West Africa, deepwater Gulf of Mexico and numerous projects in the Rocky Mountains area in 2008; and West Africa, the North Sea and deepwater Gulf of Mexico in 2007; and the North Sea and deepwater Gulf of Mexico in 2006.2007. See Item 8. Financial Statements and Supplementary Data—Data – Note 7 –7. Capitalized Exploratory Well Costs.
 
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. At December 31, 2008,2009, AOCL included a deferred loss of $3$2 million, net of tax, related to interest rate swaps. This amount is being reclassified into earnings, at the rate of $0.8 million per year, as an adjustment to interest expense over the term of our 5¼% senior notes due 2014. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
Other Non-operating (Income) Expense, netNet—   Other Non-operating (income) expense, net was as follows:
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
 Other Non-operating (Income) Expense, Net $12  $(55) $16 
Other Non-operating (income) expense, net includes deferred compensation (income) expense, interest income and other (income) expense, net. See Deferred Compensation (Income) Expense below. See also Item 8. Financial Statements – Note 2 – Summary of Significant Accounting Policies.
 
Deferred Compensation (Income) Expense—In connection with the Patina Merger in 2005, we acquired the assets and assumed the liabilities related to a deferred compensation plan. The assets of the deferred compensation plan are held in a rabbi trust and include shares of our common stock and mutual fund investments. At December 31, 2008,2009, approximately 42%45% of the market value of the assets in the rabbi trust related to our common stock. Increases in the market value of our common stock held in the trust result in the recognition of deferred compensation expense. Decreases in the market value of our common stock held in the trust result in the recognition of deferred compensation income. We recognized deferred compensation expense of $23 million in 2009, deferred compensation income of $32 million in 2008, and deferred compensation expense of $33 million in 2007 and $16 million in 2006. The amounts are included in other (income) expense, net  in the consolidated statements of operations.2007. See Item 8. Financial Statements and Supplementary Data— Data – Note 2 –2. Summary of Significant Accounting Policies and Note 12—12. Benefit Plans.
Interest Income   Interest income for 2009 includes $11 million of interest related to the refund of deepwater Gulf of Mexico royalties. See Item 8. Financial Statements and Supplementary Data – Note 2. Summary of Significant Accounting Policies.
 
Income Tax Provision (Benefit)—The income tax provision (benefit) was as follows:
 
  Year Ended December 31, 
  2009  2008  2007 
Income Tax Provision (Benefit) (millions) $(133) $711  $424 
Effective Rate  50%  35%  31%
Our effective tax rate increased to 50% for 2009 as compared with 35% for 2008 and is the result of a tax benefit divided by a pre-tax loss.  In the case of a loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate. During 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of which $9 million was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.

48
  Year Ended December 31, 
  2008  2007  2006 
Income tax provision (in millions) $711  $424  $418 
Effective rate  34.5%  31.0%  38.1%
Our effective tax rate increased in 2008 compared to 2007 primarily due to the fact that pre-tax earnings increased by a proportionately greater amount than our excludible permanent differences.  In addition, there was a rate increase due to (1) a partial shift of taxable income from lower rate jurisdictions such as Equatorial Guinea and Israel to higher rate jurisdictions, (2) the recording of US deferred taxes on the anticipated repatriation of a portion of our foreign earnings, and (3) the recording of an impairment for a foreign asset on which the tax benefit was offset by a valuation allowance.   See LiquidityItem 8. Financial Statements and Supplementary Data – Note 9. Income Taxes.
PROVED RESERVES
We have historically added reserves through our exploration program, development activities, and acquisitions of producing properties. (See Items 1. and 2.  Business and Properties). Changes in proved reserves were as follows:
  Year Ended December 31, 
  2009  2008  2007 
(MMBOE)         
Proved Reserves Beginning of Year  864   880   835 
Revisions of Previous Estimates  (64)  (44)  30 
Extensions, Discoveries and Other Additions  95   98   90 
Purchase of Minerals in Place  2   15   - 
Sale of Minerals in Place  -   (7)  (2)
Production  (77)  (78)  (73)
Proved Reserves End of Year  820   864   880 
Revisions Revisions represent changes in previous reserves estimates, either upward or downward, resulting from new information normally obtained from development drilling and production history or resulting from a change in economic factors, such as commodity prices, operating costs, or development costs. Revisions at year-end 2009 included reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s new five year development rule and lower natural gas prices, partially offset by higher crude oil prices.   Revisions at year-end 2008 were primarily due to lower year-end 2008 commodity prices. Revisions at year-end 2007 included positive revisions resulting from an increase in crude oil prices, additional production allowance related to LNG sales in Equatorial Guinea, and both positive and negative changes due to well performance.
Extensions, Discoveries and Other Additions These are additions to proved reserves that result from (1) extension of the proved acreage of previously discovered reservoirs through additional drilling in periods subsequent to discovery and (2) discovery of new fields with proved reserves or of new reservoirs of proved reserves in old fields.
In 2009, US additions were primarily driven by the execution of low-risk development projects onshore in the Wattenberg and Piceance areas, as well as from the sanctioning of the Galapagos development in the deepwater Gulf of Mexico. International additions related primarily to the initial recording of reserves at the Aseng oil project in West Africa.  In 2008, additions were due to infill drilling activities in the Northern region of our US operations, other US development programs and drilling in China. In 2007, additions were due to infill drilling activities in the Northern region and drilling activities in the deepwater Gulf of Mexico and North Sea.
We expect that a significant portion of future reserve additions will come from our major development projects at Aseng, Tamar and Gunflint; from continued drilling in the Northern region of our US operations; and from new discoveries resulting from our active exploration programs in the deepwater Gulf of Mexico and international locations. We may also purchase proved properties in strategic acquisitions.   See Operating Outlook – Major Development Project Inventory, above and Acquisition, Capital Resources–Overviewand Other Exploration Expenditures, below.
Purchases We occasionally enhance our asset portfolio with strategic acquisitions of producing properties. In 2008 we acquired producing properties in western Oklahoma. See Operating Outlook – CashPending Asset Acquisition and Cash Equivalents below.Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.
Sales   We maintain an ongoing portfolio optimization program. In 2008, we sold our Argentina asset. See Items 1. and 2. Business and Properties and Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.
Production See Oil, Gas and NGL Sales above.
See Operating Outlook – Pending Asset Acquisition, above, for a discussion of the pending acquisition of additional US Rocky Mountain assets, which we expect to add approximately 53 MMBoe of proved reserves in 2010.  See also Critical Accounting Policies and Estimates – Reserves, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
 


Several factors resulted in a decrease in our effective tax rate for 2007 as compared with 2006. The major factor was that, in 2006, $100 million of goodwill write-off associated with the sale of Gulf of Mexico shelf properties was not deductible, which increased the rate for 2006. Other factors were an increase in deferred tax assets arising from foreign tax credits, a decrease in the Chinese tax rate, and the realization of additional income from equity method investees which is a favorable permanent difference in calculating the income tax expense.
In addition to the nondeductible goodwill write-off of $100 million related to the sale of Gulf of Mexico shelf properties discussed in the preceding paragraph, the 2006 effective tax rate was impacted by decreases in our US deferred tax assets arising from future foreign tax credits due to changes in the limitation on our ability to claim foreign tax credits. In addition, a change in UK tax law increased our UK tax expense in 2006 as compared with 2005. Offsetting these increases was a reduction in the effective tax rate due to an increase in earnings from equity method investees, which is a favorable permanent difference in calculating income tax expense. See Item 8. Financial Statements – Note 9 —Income Taxes.
 
LIQUIDITY AND CAPITAL RESOURCES
 
OverviewCapital Structure/Financing Strategy
 
Our primary cash needs areIn seeking to effectively fund and monetize our development and major projects pipeline, we employ a capital structure and financing strategy designed to provide adequate liquidity throughout the commodity price cycle.  Specifically, we strive to retain the ability to fund operating expenseslong cycle capital intensive development projects while also maintaining the capability for financially attractive periodic mergers and capital expenditures relatedacquisitions activity.  We endeavor to maintain an investment grade debt rating in service of these objectives.  We also utilize a commodity price hedging program to reduce commodity price uncertainty and enhance the acquisition, explorationpredictability of cash flows along with a risk and development of crude oilinsurance program to protect against disruption to our cash flows and natural gas properties, to repay outstanding borrowings and associated interest payments and other contractual commitments and to pay dividends. operations.
Traditional sources of our liquidity are cash on hand, cash flows from operations and available borrowing capacity under our credit facilities.facility. Occasional sales of non-strategic crude oil and natural gas properties as well as our periodic access to capital markets may also generate cash.
 
 Information regarding cash and debt balances was as follows:
  December 31, 
  2009  2008  2007 
(millions, except percentages)         
Cash and Cash Equivalents $1,014  $1,140  $660 
Amount Available to be Borrowed Under Credit Facility  1,718   494   920 
Total Liquidity $2,732  $1,634  $1,580 
             
Total Debt (Excluding Unamortized Discount) $2,045  $2,270  $1,880 
Total Shareholders' Equity  6,157   6,309   4,809 
Debt-to-Capital Ratio (1)
  25%  26%  28%
(1)
We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity.
The recentongoing disruption in the credit markets hasresulted in constrained access to the debt markets in the second half of 2008 and into the first quarter of 2009. Notwithstanding these conditions, we successfully completed a debt offering in February 2009 and issued $1 billion of 8¼%, 10-year senior notes, utilizing the proceeds to pay down debt under our revolving credit facility. Since the second half of 2009, improvements in capital market conditions have increased our options for financing our capital requirements.
Disruption in the credit markets also had a significant adverse impact on a number of financial institutions. We have reviewedcontinue to review the creditworthiness of the banks and financial institutions with which we maintain our investments as well as the securities underlying our investments. Thus far, our liquidityliquidity and financial position have not been materially impacted. However, further deteriorationa recurrence of the constrained credit market conditions we experienced in the credit markets couldlate 2008 and early 2009 could adversely affect our results of operations and cash flows.  See Executive Overview -– Impact of Recession and Current Credit and Commodity Markets.
 
Cash and Cash Equivalents   – We had $1.1$1 billion in cash and cash equivalents at December 31, 2008,2009, compared with $660 million$1.1 billion at December 31, 2007. Our2008. At December 31, 2009, our cash iswas primarily denominated in US dollars and iswas invested in highly liquid, investment-grade securitiesmoney market funds and short-term deposits with original maturities of three months or less at the time of purchase.major financial institutions. Substantially all of this cash is attributable to our foreign subsidiaries and most would be subject to US income taxes if repatriated. We currently intend to use a majority of our international cash to fund international projects, including the development of our properties in West Africa.Africa and Israel.
 
DuringIn fourth quarter 2008, we performed an analysis of projected short-term working capital needs as well as long-term capital requirements for our US and foreign operations. As a result, we believe it is likely that repatriation of a portionrepatriated $180 million of the accumulated earnings of foreign subsidiaries will occur during first quarter 2009. Therefore, at December 31, 2008, we recorded deferred taxes onWe used the portion of those earnings that we expect will be repatriated. The recognition of deferred tax liabilities resulted in $9 million additional income tax expense reported in continuing operations.proceeds for debt repayment and general corporate purposes.
 
Commodity Derivative Instruments –  We use various derivative contracts in connection with anticipated crude oil and natural gas sales to minimize the impact of product price fluctuations.fluctuations and ensure cash flow for future capital needs. Such instruments include variable to fixed commodity price swaps, costless collars and basis swaps.
 
As of December 31, 2008,2009, we had commodity derivative assets totaling $470$14 million and commodity derivative liabilities totaling $25$117 million (after consideration of netting agreements). Our hedging arrangements are currently with a diversified group of 11 financial institutions, substantially all of which are lenders under our credit facility arrangement. See Item 1A. Risk Factors – Hedging transactions may limit our potential gain and Hedging transactions, receivables and cash investments expose usWe are exposed to counterparty credit risk.risk as a result of our receivables, hedging transactions, and cash investments.
 
Current period settlements on commodity derivative instruments impact our liquidity, since we are either paying cash to, or receiving cash from, our counterparties. If actual commodity prices are higher than the fixed or ceiling prices in our derivative instruments, our cash flows will be lower than if we had no derivative instruments. Conversely, if actual commodity prices are lower than the fixed or floor prices in our derivative instruments, our cash flows will be higher than if we had no derivative instruments. Except for certain minor derivative contracts that are entered into from time to time byin our marketing subsidiary,operations, none of our counterparty agreements contain margin requirements. See additional information included in Critical Accounting Policies – Commodity Derivativeand Estimates –Derivative Instruments and Hedging Activities and Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
 


CertainAccounts Receivable    We have accounts receivable from sales of our commodity contracts were executed in connection with the Patina Merger, prior to the global crude oil, and natural gas price escalations which began in early 2005.  The settlementsand NGLs, as well as electricity. We also have accounts receivable related to our joint venture partners. Some of these contractsparties are not as creditworthy as we are and may experience liquidity problems. We have reducedobtained credit enhancements from some parties in the way of parental guarantees or letters of credit, including our cash flows. However, these contracts expired in December 2008.  Our remaining commodity contracts were executed in more favorable price environments.  Although we cannot predict market prices,largest international crude oil purchaser; however, not all of our remaining commodity contract positions shouldtrade credit is protected through guarantees or credit support.  Nonperformance by a trade creditor or joint venture partner could result in more favorable cash flows as compared to our commodity contract positionslosses. Other than reductions in prior periods.the carrying value of a receivable from SemCrude, L.P., a crude oil purchaser that declared bankruptcy in 2008, and certain entities purchasing electricity in Ecuador, we have experienced no significant collection issues with purchasers or joint venture partners.  See Item 8. Financial Statements and Supplementary Data – Note 6 – Derivative Instruments and Hedging Activities for our current hedge positions.2. Summary of Significant Accounting Policies.
 
Cash Flows
 
Summary cash flow information is as follows:
 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Total Cash Provided By (Used in)         
Operating Activities $1,508  $2,285  $2,017 
Investing Activities  (1,265)  (2,132)  (1,403)
Financing Activities  (369)  327   (107)
Increase (Decrease) in Cash and Cash Equivalents $(126) $480  $507 
  Year Ended December 31, 
  2008  2007  2006 
   (in millions) 
Total cash provided by (used in):         
Operating activities $2,285  $2,017  $1,730 
Investing activities  (2,132)  (1,403)  (1,098)
Financing activities  327   (107)  (589)
Increase in cash and cash equivalents $480  $507  $43 

Operating Activities—Activities   Net cash provided by operating activities totaled $1.5 billion in 2009, a decrease of $777 million, or 34% as compared with 2008 due primarily to decreases in sales revenues resulting from significant declines in commodity prices.
Net cash provided by operating activities totaled $2.3 billion in 2008, an increase of $268 million, or 13%, as compared with 2007. The increase was primarily due to a significant increase in oil, gas and NGL sales resulting from higher average realized crude oil and natural gas prices during the first nine months of 2008. The revenue increase was slightly offset by higher production costs and G&A expense. Net cash provided by operating activities includes dividends received from equity method investees.
Net cash provided by operating activities was $2.0 billion in 2007, an increase of $287 million, or 17% as compared with 2006. The increase was due primarily to increased sales resulting from higher average realized crude oil prices and higher average realized US natural gas prices. These increases were partially offset by higher exploration expense and G&A expense. In addition, cash flows from operating activities in 2007 included dividends from equity method investees. Cash distributions from equity method investees received in 2006 were repayments of loans and were included in investing activities. See Results of Operations—Income from Equity Method Investees.
 
Investing Activities—Activities   The primary use of cash in investing activities is for capital spending, which may be offset by proceeds from property sales. Net cash used in investing activities totaled $1.3 billion in 2009, as compared with $2.1 billion in 2008. In 2009, due to the uncertain economic and commodity price environment, we designed a flexible capital spending program that was responsive to conditions that developed during 2009, and targeted an investment level of approximately $1.4 billion. Investing activities related to deepwater Gulf of Mexico lease acquisitions, exploratory activity in the deepwater Gulf of Mexico, Equatorial Guinea and Israel and development activity in the Northern region of our US operations, Equatorial Guinea and the North Sea. Net proceeds from property sales or distributions from equity method investees. totaled $3 million.
Net cash used in investing activities totaled $2.1 billion in 2008, as compared with $1.4 billion in 2007. In 2008 we had an expanded capital budget, with increased acquisition, development, exploratory, and exploratoryacquisition activity in onshore US and deepwater Gulf of Mexico areas as well as increased exploratory activity in international locations including Equatorial Guinea and Israel. Our total additions to property, plant and equipment plus acquisitions ($2.3 billion) were minimally offset by proceeds from property sales ($131 million).
 
In comparison, in 2007, we had additions to property, plant and equipment ($1.4 billion)totaled $1.4 billion, primarily due to development activity in the US and North Sea and acquisitionexploratory and exploratoryacquisition activities in the US and West Africa. Expenditures were minimally offset by proceeds from property sales of $9 million.
 
Financing Activities  In comparison,2009, net cash of $369 million was used in 2006 cash flows from investing activities totaled $1.1 billion.financing activities. We had acquisitions and additions to property, plant and equipment ($1.8 billion) due to the acquisition of U.S. Exploration plus additional development and exploratory activity in the US and development activity in the North Sea. These expenditures were offset byreceived $989 million net proceeds from the saleissuance of our significant Gulf8¼% senior notes. Funds were also provided by cash proceeds from, and tax benefits related to, the exercise of Mexico shelf propertiesstock options ($52022 million). We made net repayments of amounts outstanding under our revolving credit facility ($1.2 billion), repaid an installment note ($25 million), and repurchased a portion of our 7¼% Senior Debentures due August 1, 2097 ($4 million). We also paid cash dividends on our common stock ($126 million) and net distributions received from equity method investeesrepurchased shares of our common stock ($1511 million). The distributions from equity method investees were the result of repayment of loans and therefore were included in cash flows from investing activities. See Results of Operations—Income from Equity Method Investees.
 


Financing Activities—In 2008, net cash of $327 million was provided by financing activities. We borrowed a net $426 million under our credit facility in support of ouran expanded capital budget, noted above, which included significant domestic acquisition,exploration, development and explorationacquisition activities and as well as new international ventures. Funds were also provided by the cash proceeds from, and tax benefits related to, the exercise of stock options ($51 million). Other financing activities included the payment of cash dividends on our common stock ($115 million), the repayment of installment and other notes ($32 million) and the repurchase of stock ($3 million).

 
In comparison, in 2007, we used cash of $107 million in financing activities. Our capital expenditures, noted above, were somewhat reduced from that of 2006 resulting in a need for borrowings of only a net $25 million. Funds were also provided by thenet borrowings ($25 million) and cash proceeds from, and tax benefits related to, the exercise of stock options ($45 million). We were able to use available cash to finance the repurchase of two million shares of our common stock ($102 million) and pay cash dividends on common stock ($75 million).
In 2006, we used cash of $589 million in financing activities. We used excess cash to reduce borrowings by a net $230 million, repurchase eight million shares of our common stock ($399 million), and pay cash dividends on common stock ($49 million). Funds were also provided by the cash proceeds from, and tax benefits related to, the exercise of stock options ($8975 million).
 
Acquisition, Capital and Other Exploration Expenditures
 
Expenditure informationAcquisition, Capital and Other Exploration Expenditures   Information for investing activities (on an accrual basis) is as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Acquisition, Capital and Other Exploration Expenditures         
Unproved property acquisition (1)
 $303  $145  $185 
Proved property acquisition (2)
  255   11   523 
Exploration expenditures  448   372   203 
Development expenditures  1,193   1,175   1,055 
Corporate and other expenditures  65   36   35 
Total expenditures  2,264   1,739   2,001 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Acquisition, Capital and Exploration Expenditures         
Unproved Property Acquisition (1)
 $92  $302  $146 
Proved Property Acquisition (2)
  (5)  256   11 
Exploration  242   448   372 
Development  881   1,193   1,175 
Corporate and Other  107   65   35 
Total $1,317  $2,264  $1,739 
Non-cash Capital Lease Accrual (3) $ 29  $ -  $ - 
 
(1)
Unproved property acquisition cost for 2009 includes $56 million for deepwater Gulf of Mexico lease blocks and the remainder primarily for other onshore US lease acquisition. Unproved property acquisition cost for 2008 includes $179 million for deepwater Gulf of Mexico lease blocks, $38 million related to the Mid-continentMid-continent acquisition, $80$79 million related to additional onshore US lease acquisitions and $6 million related to international lease acquisitions. Unproved property acquisition cost for 2006 includes $131 million allocated to properties acquired in the U.S. Exploration acquisition.
(2)Proved property acquisition cost for 2008 includes $254 million related to the Mid-continent acquisition. Proved property acquisition cost for 2006 includes $413 million allocated
(3)Relates to properties acquiredestimated construction in progress to date on an FPSO to be used in the U.S. Exploration acquisition.development of the Aseng field in Equatorial Guinea.
Total expenditures in 2009 decreased by $947 million, or 42%, as compared with 2008, as we reduced our capital spending program in response to economic conditions.
 
Total expenditures in 2008 increased by $525 million, or 30%, as compared with 2007. The increase was due to increased acquisition, development, exploratory and exploratoryacquisition activity in onshore US and deepwater Gulf of Mexico areas as well as increased exploratory activity in international locations including Equatorial Guinea and Israel.
 
Total expendituresAsset Sales  In February 2008, effective July 1, 2007, we sold our interest in 2007 decreased $262 million, or 13%, as compared with 2006. The decrease was due to significantly lower acquisition expenditures, offset by exploratory activities in West Africa and the North Sea, and increased development activity in the Northern region and GulfArgentina for a sales price of Mexico area of our US operations.$117.5 million.
 
Insurance RecoveriesCoverage
 
Our corporatebusiness is subject to all of the operating risks normally associated with the exploration, production, gathering, processing and transportation of oil and gas, including hurricanes, blowouts, cratering and fire, any of which could result in damage to, or destruction of, oil and natural gas wells or formations or production facilities and other property and injury to persons. As protection against financial loss resulting from many, but not all of these operating hazards, we maintain insurance coverage, including certain physical damage, business interruption, employer’s liability, comprehensive general liability and worker’s compensation insurance.  We maintain insurance at levels that we believe are appropriate and consistent with industry practice and we regularly review our potential risks of loss and the cost and availability of insurance and revise our insurance program provides up to $260 million property damage coverage per loss event. However, our insurance carrier’s aggregation limit for catastrophic windstorm events is $750 million. If an insured catastrophic loss event occurs, we could still recover less than our stated limits should the total aggregate losses realized by our carrier exceed its $750 million aggregation limit that is applicable to any single loss event.accordingly.
 
We carry additionalare a member in Oil Insurance Limited (OIL). OIL is a mutual insurance company which insures property, damage andpollution liability, control of well coverage for our deepwater Gulf of Mexico and remaining Gulf of Mexico shelf properties. This additionalother catastrophic risks. Effective January 1, 2010, windstorm insurance provides up to $100 million in additional coverage for certain claims which exceed the $260 million property damage coverage or where the $260 million property damage coverage is reduced by applicationprovided subject to a $10 million per-occurrence deductible, a $150 million per-occurrence loss limit per member, an annual maximum of $300 million per member, and a $750 million industry aggregate per-event loss limit. Annual industry windstorm losses exceeding $300 million will be mutualized among windstorm members in two pools, one for offshore losses and one for onshore losses, with future premiums based upon a pool’s loss experience and a member’s weighted percent of the $750 million aggregation limit.pool’s asset base. As a result of our recent asset retirement efforts at Main Pass, our risk of windstorm damage has been reduced.  We have not yet determined whether we will seek additional third party insurance to replace the reduction in OIL coverage. See Contractual Obligations below for a discussion of our theoretical withdrawal premium liability.
For certain international locations (including Israel, Equatorial Guinea and Ecuador) we carry business interruption insurance for certain international locations.loss of revenue arising from physical damage to our facilities caused by fire and natural disasters. The coverage is subject to customary deductibles, waiting periods and recovery limits.
 


Financing Activities
 
Long-Term Debt—Debt   Our long-term debt totaled $2.245$2 billion (excluding unamortized discount) at December 31, 2008, and2009, with maturities rangeranging from 2012 to 2097. Our principal source of liquidity is an unsecured revolving credit facility that matures December 9, 2012. The commitment is $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The credit facility (i) provides for credit facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the credit facility. At December 31, 2008, $1.606 billion2009, $382 million in borrowings were outstanding under the credit facility, leaving $494 million$1.7 billion available for use. The weighted average interest rate applicable to borrowings under the credit facility at December 31, 20082009 was 0.80%0.54%. We expect to use the credit facility to fund our planned $494 million acquisition of US Rocky Mountain assets in the first quarter 2010.
 
The credit facility contains customary representations and warranties and affirmative and negative covenants. The credit facility requires that our total debt to capitalization ratio (as defined in the credit agreement), expressed as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the credit facility, which would permit the participating banks to restrict our ability to access the credit facility and require the immediate repayment of any outstanding advances under the credit facility. As of December 31, 2009, we were in compliance with our debt covenants.
 
The credit facility is with certain commercial lending institutions and isits funds are available for general corporate purposes. Our bank group is comprised of 2423 commercial lending institutions, each holding between 1.0% and 7.0%11.4% of the total facility.  Due to recent consolidation in the banking sector resulting from heightened stress in the credit markets, the number of lenders and their effective commitment levels within our credit facility may be reallocated over time.
 
We also have $639On February 27, 2009, we closed an offering of $1 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees, and used substantially all of the net proceeds to repay outstanding indebtedness under our credit facility.  The notes are due March 1, 2019, and pay interest semi-annually at 8¼%.
Including our new 8¼% notes, we had a total of $1.6 billion of fixed-rate debt outstanding at December 31, 20082009 with a weighted average interest rate of 6.92%7.73%. Maturities range from 2014 to 2097.
 
Credit Rating   Our senior unsecured debt is rated investment grade by both of the industry's recognized rating agencies.  We are currently rated Baa2/Stable Outlook from Moody's and BBB/Stable Outlook from Standard & Poor's.   Our latest rating action was an upgrade by Standard & Poor's in February 2009.  The ratings reflect the agencies' view of our positive financial metrics due to our strong liquidity and conservative financial profile.   Factors that could negatively pressure ratings could be driven by an overall negative industry outlook precipitated by a decline in oil and natural gas prices to levels that are likely to result in weak cash margins and fundamental credit deterioration or factors specific to us, such as deterioration in operating performance resulting in reduced cost competitiveness, lower capital productivity or events leading to a higher debt leverage profile in the capital structure.   Adverse rating actions by the credit agencies would not trigger a covenant default in our credit facility or in any of our publicly held debt securities.
Short-Term Borrowings— We owe   In May 2009, we made the final $25 million in the form of an installment payment to the seller of properties we purchased in 2007. The amount is due May 11, 2009 and is included in short-term borrowings in the consolidated balance sheets. Interest on the unpaid amount iswas due quarterly and accruesaccrued at a LIBOR rate plus .30%..30%. The interest rate was 4.18%1.51% at December 31, 2008.the date of payment.
 
Our committed credit facility has been supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. There were no amounts outstanding under uncommitted credit lines at December 31, 20082009 or 2007.2008. Depending upon future credit market conditions, these sources may or may not be available. However, we are not dependent on them to fund our day-to-day operations.
 
Ratio of Debt-to-Book Capital  — Our ratio of debt-to-book capital has decreased from 28%was 25% at December 31, 2007 to2009 and 26% at December 31, 2008. We define our ratio of debt-to-book capital as total debt (which includes both long-term debt, excluding unamortized discount, and short-term borrowings) divided by the sum of total debt plus shareholders’ equity. Significant changes in our financial position causing a change in the ratio of debt-to-book capital included the following:
 
·$1.4 billion increase225 million decrease in shareholders’ equitytotal principal amount of debt from current year net income;the balance at December 31, 2008;
offset by
 ·$390131 million increasedecrease in total debtshareholders’ equity from the balance at December 31, 2007;current year net loss; and
 ·$115126 million decrease in shareholders’ equity from dividends paid.
 
Interest Rate Locks—We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. As of December 31, 2007, we had entered into two interest rate locks, each in the notional amount of $500 million. The locks were based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively, and were scheduled to expire in September 2008. We settled the locks in July 2008 at a total cost of $0.2 million.


In January 2010, in anticipation of a long-term debt issuance, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on the anticipated debt issuance. The swap is in the notional amount of $500 million and is based on a 30-year LIBOR swap rate.
 
Cash Interest Payments—We made cash interest payments of $97 million in 2009, $109 million in 2008, and $122 million in 2007 and $119 million in 2006.2007.
 
Exercise of Stock Options—Options   Proceeds from the exercise of stock options totaled $17 million in 2009, $27 million in 2008, and $25 million in 2007 and $63 million in 2006.2007. Proceeds received from the exercise of stock options fluctuate primarily based on the number of options exercised which is influenced by the price at which our common stock trades on the NYSE in relation to the exercise price of the options issued.
 
Dividends—Dividends   We paid cash dividends totaling 66.072 cents per common share in 2009, 66 cents per common share in 2008, and 43.5 cents per common share in 2007 and 27.5 cents per common share in 2006.2007. On January 27, 2009,26, 2010, the Board of Directors declared a quarterly cash dividend of $0.1818 cents per common share, which will be paid February 23, 200922, 2010 to shareholders of record on February 9, 2009.8, 2010. The amount of future dividends will be determined on a quarterly basis at the discretion of the Board of Directors and will depend on earnings, financial condition, capital requirements and other factors.
 


Common Stock Repurchases—In 2008, we received   We receive shares of our common stock from employees approximately 33,000 shares of common stock with a total value of $3 million for the payment of withholding taxes due on the vesting of restricted shares issued under stock-based compensation plans. We received approximately 21,000 shares with a total value of $1 million in 2009 and approximately 33,000 shares with a total value of $3 million in 2008. In 2007, we completed a common stock repurchase program authorized by our Board of Directors in 2006. We2006 and repurchased two million shares of our common stock at an aggregate cost of $102 million in 2007 and 8.4 million shares of our common stock at an aggregate cost of $399 million in 2006, resulting in a total of 10.4 million shares acquired at an average price of $48.17 per share.million.
 
Off-Balance Sheet Arrangements
We may enter into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations. As of December 31, 2008,2009, the material off-balance sheet arrangements and transactions that we have entered into included drilling service contracts, operating lease agreements, and undrawn letters of credit.credit, all of which are customary in the oil and gas industry. Other than the off-balance sheet arrangements listed above, we have no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources. See Contractual Obligations below for more information regarding off-balance sheet arrangements.
 
Contractual Obligations
 
The following table summarizes certain contractualcontractual obligations that are reflected in the consolidated balance sheets and/or disclosed in the accompanying notes. Unless otherwise noted, all amounts are net to our interest.
 
  Payments Due by Period 
        2010  2012  2014 and 
  Total  2009  and 2011  and 2013  Beyond 
  (in millions) 
Long-term debt (excluding interest) (1)
 $2,270  $25  $-  $1,606  $639 
Drilling and equipment obligations: (2)
                    
United States  752   70   613   69   - 
International  480   252   225   3   - 
Purchase obligations (3)
  163   163   -   -   - 
Throughput agreement (4)
  95   14   38   38   5 
Transportation and gathering (5)
  43   12   17   10   4 
Operating lease obligations (6)
  56   12   18   8   18 
Other long-term liabilities: (7)
                    
Asset retirement obligations (8)
  211   27   18   29   137 
Commodity derivative instruments (9)
  25   23   2   -   - 
Total contractual obligations $4,095  $598  $931  $1,763  $803 
  Total  2010  2011 and 2012  2013 and 2014  2015 and beyond 
(millions)               
Long-Term Debt (Excluding Interest) (1)
 $2,016  $-  $382  $200  $1,434 
Obligation Under FPSO Lease (2)
  468   -   35   138   295 
Drilling and Equipment Obligations (3)
                    
United States  461   259   202   -   - 
International  269   147   122   -   - 
Purchase Obligations (4)
  304   265   39   -   - 
Throughput Agreement (5)
  81   19   38   24   - 
Transportation and Gathering (6)
  40   11   17   9   3 
Operating Lease Obligations (7)
  83   12   19   21   31 
Other Long-Term Liabilities (8)
                    
Asset Retirement Obligations (9)
  232   51   31   7   143 
Commodity Derivative Instruments (10)
  117   100   17   -   - 
Total Contractual Obligations $4,071  $864  $902  $399  $1,906 
 
(1)
BasedLong-term debt excludes obligation under FPSO lease. Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2008,2009, our cash payments for interest would be $58 million in 2009, $57$128 million in 2010, $57$128 million in 2011, $56$128 million in 2012, $44$126 million in 2013, $121 million in 2014 and $878 million$1.2 billion for the remaining years for a total of $1.2$1.8 billion. See Item 8. Financial Statements and Supplementary Data—Data – Note 8—8. Debt.
(2)
The FPSO is currently under construction. Annual lease payments, net to our interest, exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations. These payments are also subject to change based on change orders implemented during the construction period, final accounting treatment, and other factors.  See Item 8. Financial Statements and Supplementary Data – Note 8. Debt.
(3)Drilling and equipment obligations represent contractual agreements with third party service providers to procure drilling rigs and other related equipment for developmental and exploratory drilling activities.  See Item 8. Financial Statements and Supplementary Data—Data – Note 17—17. Commitments and Contingencies.


(3)(4)Purchase obligations represent agreements to purchase goods or services that are enforceable, are legally binding and specify all significant terms, including fixed and minimum quantities to be purchased; fixed, minimum or variable price provisions; and the approximate timing of the transaction. See Item 8. Financial Statements and Supplementary Data—Data – Note 17—17. Commitments and Contingencies.
(4)(5)
We have a five-year throughput agreement on a new interstate crude oil transportation pipeline system running from Weld County, Colorado to Cushing, Oklahoma, which is expected to becomebecame operational in 2009. See Item 8. Financial Statements and Supplementary Data—Data – Note 17—17. Commitments and Contingencies.
(5) (6)
Transportation and gathering obligations represent minimum changescharges for our firm transportation and gathering agreements. See Item 8. Financial Statements and Supplementary Data —– Note 17—17. Commitments and Contingencies.
 (6)(7)
Operating lease obligations represent non-cancelable leases for office buildings and facilities and oil and gas operations equipment used in our daily operations. See Item 8. Financial Statements and Supplementary Data  —– Note 17—17. Commitments and Contingencies.


(7)(8)
The table excludes deferred compensation liabilities of $159$213 million and accrued benefit costs of $81$76 million as specific payment dates are unknown. See Item 8. Financial Statements and Supplementary Data—Data – Note 12—12. Benefit Plans.
(8)(9)
Asset retirement obligations are discounted. See Item 8. Financial Statements and Supplementary Data—Data – Note 10—10. Asset Retirement Obligations.
(9)(10)
Amount represents open commodity derivative instruments that were in a net payable position with the counterparty at December 31, 2008.2009. Our remaining commodity derivative instruments were in a net receivable position at December 31, 2008.2009. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
We accrued approximately $20 million asAs of December 31, 2008,2009, we accrued approximately $28 million for an insurance contingency due to our membership in Oil Insurance Limited (OIL).OIL. OIL is a mutual insurance company which insures specific property, pollution liability and other catastrophic risks. As part of our membership, we are contractually committed to pay termination fees should we elect to withdraw from OIL. We do not anticipate withdrawing from OIL; however, the potential termination fee is calculated annually based on OIL’s past losses and the liability reflecting this potential charge has been accrued.
 
In addition, in the ordinary course of business, we maintain letters of credit in support of certain performance obligations of our subsidiaries. Outstanding letters of credit totaled approximately $5$4 million at December 31, 2008.2009.
 
Other
 
Contributions to Pension and Other Postretirement Benefit Plans—We made contributions to the pension and other postretirement benefit plans totaling $21 million in 2009, $38 million in 2008, and $12 million in 2007, and $36 million in 2006.2007. The actual return on plan assets was a gain of $33 million in 2009, and a loss of $43 million in 2008 and a gain of $13 million in 2007.2008. The investment return has tended to follow market performance. In August 2006, the Pension Protection Act of 2006 (the Act) was signed into law. Certain provisions of this Act changed the calculation related to the maximum contribution amount deductible for income tax purposes and require that defined benefit pension plans become fully funded over a seven-year period beginning in 2008. As a result of previous contributions made to the pension plan, the plan is adequately funded at the balance sheet date, and we expect the plan would not be subject to any of the benefit limitations that would be imposed by the Act if the plan were not adequately funded.  In addition, due to the level of previous funding, we do not expect that there are any contributions that will be required in 2009.2010. However, we made a contribution of $2 million to the pension plan in January 2010 and may make additional contributions to our pension plan. In 2009, wethe plan during 2010. We expect to make contributions pertaining to the restoration and medical and life plans of approximately $3 million during 2010, an amount which is estimated to be equal to the benefits expected to be paid by those plans.
 
Income Taxes—Taxes   We made cash payments for income taxes, net of refunds, of $227 million in 2009, $263 million in 2008, and $149 million in 2007, and $115 million in 2006.2007.
 
Contingencies—Contingencies   We paid a total of approximately $2 millionPayments to settle legal proceedings totaled approximately $19 million in 2009, $2 million in 2008, and $56 million to settle legal proceedings in 2007. These amounts had been accrued previously. During 2006, no significant payments were made to settle any legal proceedings. We regularly analyze current information and accrue for probable liabilities on the disposition of certain matters, as necessary. Liabilities for loss contingencies arising from claims, assessments, litigation or other sources are recorded when it is probable that a liability has been incurred and the amount can be reasonably estimated.
 
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
The preparation of the consolidated financial statements requires our management to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosures of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the period. When alternatives exist among various accounting methods, the choice of accounting method can have a significant impact on reported amounts. The following is a discussion of the accounting policies, estimates and judgments which management believes are most significant in the application of generally accepted accounting principles used in the preparation of the consolidated financial statements.
 
Reserves—All of the reservereserves data in this Form 10-K are estimates.estimates. Estimates of our crude oil and natural gas reserves are prepared by our engineers in accordance with guidelines established by the SEC.SEC, including the recent rule revisions designed to modernize the oil and gas company reserves reporting requirements and which we adopted effective December 31, 2009. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Uncertainties include the projection of future production rates and the expected timing of development expenditures. The accuracy of any reservereserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reservereserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. In addition, economic producibility of reserves is dependant on the oil and gas prices used in the reserves estimate. We based our December 31, 2009 reserves estimates on a 12-month average commodity price, unless contractual arrangements designate the price to be used, in accordance with SEC rules. However, oil and gas prices are volatile and, as a result, our reserves estimates will change in the future.


Estimates of proved crude oil and natural gas reserves significantly affect our DD&A expense.


For example, if estimates of proved reserves decline, the DD&A rate will increase, resulting in a decrease in net income. A decline in estimates of proved reserves could also cause us to perform an impairment analysis to determine if the carrying amount of crude oil and natural gas properties exceeds fair value and could result in an impairment charge, which would reduce earnings. In addition, a decline in estimates of proved reserves could prompt a goodwill impairment analysis. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
 
Oil and Gas Properties—We account for crude oil and natural gas properties under the successful efforts method of accounting. Under the successful efforts method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find commercial quantities of proved reserves, and to drill and equip development wells are capitalized. Proved property acquisition costs are amortized to expense by the unit-of-production method on a field-by-field basis based on total proved crude oil and natural gas reserves as estimated by our engineers. Costs to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are also amortized to expense by the unit-of-production method on a field-by-field basis. These costs, along with support equipment and facilities, are amortized based on proved developed crude oil and natural gas reserves. Costs of certain gathering facilities or processing plants serving a number of properties or used for third partythird-party processing are depreciated using the straight-line method over the useful lives of the assets. Application of the successful efforts method results in the expensing of certain costs including geological and geophysical costs, exploratory dry holes and delay rentals, during the periods the costs are incurred.
 
The alternative method of accounting for crude oil and natural gas properties is the full cost method. Under the full cost method, geological and geophysical costs, exploratory dry holes and delay rentals are capitalized as assets and charged to earnings in future periods as a component of DD&A expense. In addition, under the full cost method, capitalized costs are accumulated in pools on a country-by-country basis. DD&A is computed on a country-by-country basis, and capitalized costs are limited on the same basis through the application of a ceiling test. We believe the successful efforts method is the most appropriate method to use in accounting for our crude oil and natural gas properties because it provides a better representation of results of operations, especially during periods of active exploration. If we had used the full cost method, our financial position and results of operations could have been significantly different.
 
Exploratory Well Costs—In accordance with the successful efforts method of accounting, the costs associated with drilling an exploratory well may be capitalized temporarily, or “suspended,” pending a determination of whether commercial quantities of crude oil or natural gas have been discovered. We carry the costs of an exploratory well as an asset if the well has found a sufficient quantity of reserves to justify its completion as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take several years to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained.
 
Management assesses the status of suspended exploratory well costs on a quarterly basis. These costs may be charged to exploration expense in future periods if we decide not to pursue additional exploratory or development activities. At December 31, 2008,2009, the balance of property, plant and equipment included $501$432 million of suspended exploratory well costs, $245$274 million of which had been capitalized for a period greater than one year. The wells relating to these suspended costs continue to be evaluated by various means including additional seismic work, drilling additional appraisal wells to confirm the size of the hydrocarbon deposit, or evaluating the potential commerciality of the exploration wells. For more information, seeSee Item 8. Financial Statements and Supplementary Data—Data – Note 7—7. Capitalized Exploratory Well Costs.
 
Impairment of Proved Oil and Gas Properties and Other Investments—We assess proved crude oil and natural gas properties and other investments for possible impairment when events or circumstances indicate that the recorded carrying value of the assets may not be recoverable. We recognize an impairment loss as a result of an event that causes us to consider the possibility that an impairment may have occurred and when the estimated undiscounted future cash flows from a property or other investment are less than the carrying value. If impairment is indicated, the carrying values are written down to fair value, which, in the absence of comparable market data, is estimated using a discounted cash flow method. In our cash flow method, cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. Estimated future cash flows are based on management’s expectations for the future and include estimates of crude oil and natural gas reserves and future commodity prices, revenues and operating and development costs. Downward revisions in estimates of reservereserves quantities or expectations of falling commodity prices or rising operating or development costs could result in a reduction in undiscounted future cash flows and could indicate property impairment.
 


WeDuring 2009, we assessed the recoverability of ourcertain proved oil and gas properties and other investments at December 31, 2008. As a result of this analysis, we determined that certain of ourfor possible impairment due to lower commodity prices and/or performance issues. Certain assets were determined to be impaired. In addition, during third quarter 2008, we recorded an impairment charge related to an asset held for sale. For 2008 total pre-tax (non-cash) asset impairment charges, assessed under SFAS 144, were approximately $219 million of which $149 million is related to our US proved properties and $70 million related to our investment in Ecuador. TheseThe impaired assets were written down to their estimated fair values under a discounted cash flowsflow model. The discounted cash flowsflow model included management’s estimates of future oil and gas production; commodity prices based on December 31, 2008forward commodity price strips;curves at the date of the estimate; operating and development costs, as well as appropriateand discount rates. We also determined that our investment in Ecuador was impaired.
We recorded total pre-tax (non-cash) asset impairment charges of $604 million in 2009, $219 million in 2008 and $4 million in 2007. See Item 8. Financial Statements and Supplementary Data—Data – Note 3—3. Asset Impairments. We recorded approximately $4 million of impairments in 2007 and $9 million in 2006, primarily related to downward reserve revisions on US properties and/or adjustment of the carrying value of properties to their fair values.
 
Impairment of Unproved Oil and Gas Properties—We also perform periodic assessments of individually significant unproved crude oil and natural gas properties for impairment on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploratory activity on the property being evaluated and/or adjacent leaseholds,properties, our geologists' evaluation of the lease,property, and the remaining months in the lease term.term for the property.
 
When we have allocated fair values to a significant unproved property as the result of a business combination or other purchase of proved and unproved properties, we use a future cash flow analysis to assess the property for impairment.  Cash flows used in the impairment analysis are determined based upon management’s estimates of natural gas and crude oil reserves, including probable and possible reserves, future commodity prices and future costs to extract the reserves Probable reserves are defined in SEC Regulation S-X, Rule 4-10(a)(18) as 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. Possible reserves are defined in SEC Regulation S-X, Rule 4-10(a)(17) as those additional reserves that are less certain to be recovered than probable reserves. 
Downward revisions in estimated reservereserves quantities, reductions in commodity prices, or increases in estimated costs could cause a reduction in the value of an unproved property and, therefore, could also cause a reduction in the carrying amount of the property. If undiscounted future net cash flows are less than the carrying value of the property, indicating impairment, the cash flows are discounted using a risk-adjusted rate and compared to the carrying value for determining the amount of the impairment loss to record. The estimated prices used in the cash flow analysis are determined by management based on forward commodity price curves foras of the related commodities,date of the estimate, adjusted for average historical location and quality differentials. Estimates of cash flows related to probable and possible reserves are reduced by additional risk-weighting factors.
 
Due to the volatility of natural gas and crude oil prices, these cash flow estimates are inherently imprecise. Management’s assessment of the results of exploration activities, availability of funds for future activities and the current and projected political climate in areas in which we operate also impact the amounts and timing of impairment provisions.
 
We assessed the recoverability of our significant unproved oil and gas properties at December 31, 2008. Due to the decrease in commodity prices, we recorded a pre-tax (non-cash) impairment charge of $75 million related to our US unproved properties. These impairments were primarily related to allocated fair value attributable to probable2009 and possible reserves acquired in previous business combinations. We assessed these properties under a discounted cash flows model based on management’s assumptions of future oil and gas production, commodity prices, operating and development costs; as well as appropriate discount rates. See Item 8. Financial Statements and Supplementary Data—Note 3—Asset Impairments.   determined there was no impairment.
We recorded impairments of significant unproved oil and gas properties of $75 million in 2008 and $3 million in 20072007. See Item 8. Financial Statements and $1 million in 2006 and reported the amounts in exploration expense.Supplementary Data – Note 3.  Asset Impairments.
 
Purchase Price Allocations—As a result of the Patina Merger in 2005 and the U.S. Exploration acquisition in 2006, we acquired assets and assumed liabilities in transactions accounted for as purchases. In connection with a purchase business combination, the acquiring company must allocate the cost of the acquisition to assets acquired and liabilities assumed based on fair values as of the acquisition date. Deferred taxes must be recorded for any differences between the assigned values and tax bases of assets and liabilities. Any excess of purchase price over amounts assigned to assets and liabilities is recorded as goodwill. The amount of goodwill recorded in any particular business combination can vary significantly depending upon the value attributed to assets acquired and liabilities assumed.
 
In estimating the fair values of assets acquired and liabilities assumed we made various assumptions. The most significant assumptions related to the estimated fair values assigned to proved and unproved crude oil and natural gas properties. To estimate the fair values of these properties, we prepared estimates of crude oil and natural gas reserves. We estimated future prices to apply to the estimated reservereserves quantities acquired, and estimated future operating and development costs, to arrive at estimates of future net cash flows. For estimated proved reserves, the future net cash flows were discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the acquisition. The market-based weighted average cost of capital rate was subjected to additionaladditional project-specific risking factors. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves were reduced by additional risk-weighting factors.
 


 
Estimated deferred taxes were based on available information concerning the tax basisbases of assets acquired and liabilities assumed and loss carryforwards at the merger date, although such estimates may change in the future as additional information becomes known.
 
Estimated fair values assigned to assets acquired can have a significant effect on results of operations in the future. A higher fair value assigned to a property results in higher DD&A expense, which results in lower net earnings. Fair values are based on estimates of future commodity prices, reservereserves quantities, operating expenses and development costs. This increases the likelihood of impairment if future commodity prices or reservereserves quantities are lower than those originally used to determine fair value, or if future operating expenses or development costs are higher than those originally used to determine fair value. Impairment would have no effect on cash flows but would result in a decrease in net income for the period in which the impairment is recorded.
 
Goodwill—As of December 31, 2008,2009, the consolidated balance sheet included $759$758 million of goodwill, all of which has been assigned to the US reporting unit. Goodwill is not amortized to earnings but is tested, at least annually, for impairment at the reporting unit level. We conduct the goodwill impairment test as of December 31 of each year. Other events and changes in circumstances may require goodwill to be tested for impairment between annual measurement dates. If the carrying value of goodwill is determined to be impaired, the amount of goodwill is reduced and a corresponding charge is made to earnings in the period in which the goodwill is determined to be impaired.
 
A two-step impairment test is used to identify potential goodwill impairment and measure the amount of a goodwill impairment loss to be recognized. The first step of the goodwill impairment test, used to identify potential impairment, compares the fair value of a reporting unit with its carrying amount, including goodwill. If the fair value of the reporting unit exceeds its carrying amount, goodwill is not considered to be impaired, and the second step of the test is not required.  If necessary, the second step of the impairment test, used to measure the amount of impairment loss, compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to the excess.
 
The first step of the impairment test requires management to make estimates regarding the fair value of the reporting unit to which goodwill has been assigned. In determining the fair value of the US reporting unit, we use a combination of the income approach and the market approach.
 
Under the income approach, the fair value of the US reporting unit is estimated based on the present value of expected future cash flows.  The income approach is dependent on a number of factors including estimates of forecasted revenue and operating costs, proved reserves, as well as the success of future exploration for and development of unproved reserves, appropriate discount rates and other variables. Downward revisions of estimated reservereserves quantities, increases in future cost estimates, divestiture of a significant component of the reporting unit, or sustained decreases in natural gas or crude oil prices could lead to a reduction in expected future cash flows and possibly an impairment of all or a portion of goodwill in future periods.
 
Key assumptions used in the discounted cash flowsflow model described above include estimated quantities of oil and gas reserves, including both proved reserves and risk-adjusted unproved reserves; estimates of futuremarket prices considering forward commodity prices based on theprice curves in place as of December 31, 2008 commodity price strips;2009; and estimates of operating, administrative and capital costs adjusted for inflation. We discounted the resulting future cash flows using a peer company based weighted average cost of capital of 9%10%.
 
Under the market approach, we estimated the value of the US reporting unit by comparison to similar businesses whose securities are actively traded in the public market. This requires management to make certain judgments about the selection of comparable companies and/or comparable recent company and asset transactions and transaction premiums. At December 31, 2008,2009, we used a peer company multiple method for the market approach.  Market multiples represent market estimates of fair value based on selected financial metrics, such asmetrics. We use earnings before interest, taxes, DD&A and exploration expense (also known as “EBITDAX”). as our financial metric as it more accurately compares companies using successful efforts and full cost accounting methods, both of which are in our peer group.
 
Using the range of US reporting unit fair values provided by the income and market approaches as of December 31, 2008,2009, we determined that the fair value of our US reporting unit substantially exceeded its carrying amount. Therefore, the second step of the goodwill impairment test was unnecessary, and no goodwill impairment was recognized.
 
Although we have based the fair value estimate of the US reporting unit on assumptions we believe to be reasonable, those assumptions are inherently unpredictable and uncertain and actual results could differ from the estimate. In the event of a prolonged global recession, commodity prices may stay depressed or decline further, thereby causing the fair value of the US reporting unit to decline, which could result in an impairment of goodwill.
 


When we dispose of a reporting unit or a portion of a reporting unit that constitutes a business, we include goodwill associated with that business in the carrying amount of the business in order to determine the gain or loss on disposal. The amount of goodwill to be included in that carrying amount is based on the relative fair value of the business to be disposed of and the portion of the reporting unit that will be retained. During 2006, we allocated $100 million of US reporting unit goodwill to the carrying amount of Gulf of Mexico shelf properties sold. The amount of goodwill allocated to the carrying amount of a business can significantly impact the amount of gain or loss recognized on the sale of that business.


 
Commodity Derivative Instruments and Hedging Activities—We use various derivative instruments   In order to minimize the impact ofreduce commodity price fluctuations on forecasted salesuncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, production. We also use derivative instruments in connectionwe enter into crude oil and natural gas price hedging arrangements with purchases and salesrespect to a portion of third-party production to lock in profits or limit exposure to commodity price risk.our expected production. In addition, we have used derivative instruments in connection with acquisitions and certain price-sensitive projects. Management exercises significant judgment in determining types of instruments to be used, production volumes to be hedged, prices at which to hedge and the counterparties’ creditworthiness. We accountIn accordance with US GAAP for derivative instruments under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities, as amended”, andhedging activities, all derivative instruments are reflected at fair value in our consolidated balance sheets.
 
Our open commodity derivative instruments were in a net receivablepayable position with a fair value of $445$103 million at December 31, 2008.2009. We estimated the fair values of our commodity derivative instruments in accordance with SFAS 157, “Fair Value Measurements” (SFAS 157), which we adopted as of January 1, 2008.US GAAP for fair value measurements. In order to determine the fair value at the end of each reporting period, we compute discounted cash flows for the duration of each commodity derivative instrument using the terms of the related contract. Inputs consist of published forward commodity price curves for the underlying commodities as of the date of the estimate. We compare these prices to the price parameters contained in our hedge contracts to determine estimated future cash inflows or outflows. We then discount the cash inflows or outflows using a combination of published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values of our commodity derivative assets and liabilities include a measure of credit risk based on current published credit default swap rates. In addition, for costless collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters.  We compare our estimates of fair value with those provided by our counterparties. There have been no significant differences.
 
Changes in the fair values of our commodity derivative instruments have a significant impact on our net income because we follow mark-to-market accounting and recognize all gains and losses on such instruments in earnings in the period in which they occur. For the year ended December 31, 2008,2009, we reported a $440$110 million gainmark-to-market loss on commodity derivative instruments. See Item 7. Quantitative and Qualitative Disclosures About Market Risk – Commodity Price Risk and Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
Asset Retirement ObligationObligations—Our asset retirement obligations (ARO) consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. SFAS No. 143, “Accounting for Asset Retirement Obligations,”US GAAP requires that the fair value of a liability for an ARO be recognized in the period in which it is incurred with the associated asset retirement cost capitalized as part of the carrying cost of the oil and gas asset. The recognition of an ARO requires that management make numerous estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. In periods subsequent to initial measurement of the ARO, we recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Revisions also result in increases or decreases in the carrying cost of the oil and gas asset. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized cost, including revisions thereto, is charged to expense through DD&A. Asset retirement obligations totaled $211$232 million at December 31, 2008.2009. See Item 8. Financial Statements and Supplementary Data—Data – Note 10—10. Asset Retirement Obligations.
 
Involuntary Conversions—When an involuntary conversion occurs, such as the destruction of oil and gas producing assets by a hurricane, a loss is accrued by a charge to income if the amount of loss can be reasonably estimated. An asset relating to insurance recovery is recognized only when realization of the claim for recovery of a loss recognized in the financial statements is deemed probable. A gain (recovery of a loss not yet recognized in the financial statements or an amount recovered in excess of a loss recognized in the financial statements) is not recognized until the insurance reimbursement has been received.
 
Management must make a number of estimates and assumptions relating to these gain and loss accruals. These include estimated costs of salvage, clean-up, restoration, redevelopment or abandonment and estimated amounts of insurance recoveries. The amount of an insurance recovery may be limited if total industry claims are in excess of the insurance carrier’s ceiling limitation per event. A significant amount of time may be necessary for an insurance carrier to review all related claims for an event and determine the company-specific claim limitation on the final recovery. In addition, we may continue to incur costs, submit claims and receive reimbursements over a multi-year period.


 
The estimates involved in this process can have significant effects on reported amounts of net income. A decrease in the estimated amount of insurance recoveries will result in an increase in the involuntary conversion loss, which will result in a decrease in net income. An increase in estimated costs of salvage, if not covered by insurance, will also result in an increase in the involuntary conversion loss, which will result in a decrease in net income. Unreimbursed losses will have a negative effect on our cash flows. During the first half of 2007, several factors contributed to an increase in our estimated cleanup costs for damage related to Hurricanes Ivan in 2004 and Katrina in 2005.  These factors included cost escalation due to weather delays and an increase in effort for the design and construction of the deck lifting barge and mooring system, as well as additional costs for the actual deck lifting activities.  These increases caused the total project costs, combined with net book value of the assets destroyed, to exceed certain insurance coverage limitations.  As a result, we recorded $51 million as a loss on involuntary conversion duringin 2007.  DuringIn 2008, we recorded an additional $9 million loss on involuntary conversion upon resolution of certain of our insurance claims related to the hurricane damage sustained in 2005. In 2009, we recorded a net gain of $9 million representing receipt of insurance claims related to damage caused by Hurricanes Katrina and Rita. See Item 8. Financial Statements and Supplementary Data—Data – Note 2—2. Summary of Significant Accounting Policies.


 
Income Tax Expense and Deferred Tax Assets—We are subject to income and other taxes in numerous taxing jurisdictions worldwide. For financial reporting purposes, we provide taxes at rates applicable for the appropriate tax jurisdictions. Estimates of amounts of income tax to be recorded involve interpretation of complex tax laws, assessment of the effects of foreign taxes on domestic taxes, and estimates regarding the timing and amounts of future repatriation of earnings from controlled foreign corporations.
 
The consolidated balance sheets include deferred tax assets. Deferred tax assets arise when expenses are recognized in the financial statements before they are recognized in the tax returns or when income items are recognized in the tax return before they are recognized in the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Ultimately, realization of a deferred tax asset depends on the existence of sufficient taxable income within the future periods to absorb future deductible temporary differences, loss carryforwards or credits. In assessing the realizability of deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. We continue to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration. As a result, we may determine, and we have determined in the past, that a deferred tax asset valuation allowance should be established. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.
 
As of December 31, 2008,2009, the accumulated undistributed earnings of our foreign subsidiaries on which no US taxes have been recorded totaled approximately $1.1$1.2 billion. Management must consider numerous factors in determining timing and amounts of possible future distribution of these earnings to the parent company and whether a US deferred tax liability should be recorded for these earnings. These factors include the future operating and capital requirements of both the parent company and the subsidiaries, remittance restrictions imposed by foreign governments or financial agreements and tax consequences of the remittance, including possible application of US foreign tax credits and limitations on foreign tax credits that may be imposed by the Internal Revenue Service (IRS) or IRS regulations. We currently believe that
In first quarter 2009, we repatriated $180 million of accumulated earnings of foreign subsidiaries and used the proceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of a portion of our international undistributed earnings is likely. Therefore, as of December 31, 2008, we have recorded additional US deferred income taxes ofwhich $9 million on the portion of undistributed earnings of our foreign subsidiaries that we anticipate will be repatriated.was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows.flows due to the payment of additional taxes. We currently intend to use a majority of our international cash to fund international projects, including the development of our properties in West Africa and Israel. However, we estimate that a repatriation of $1 billion as of December 31, 2009, if we had elected not to use the cash to fund international development, would have had a net cash tax impact of approximately $195 million. This amount is net of estimated foreign tax credits.
 
Allowance for Doubtful Accounts—We assess the recoverability of all material trade and other receivables to determine their collectibility on a quarterly basis. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated. In determining the amount of the reserve, management must analyze the aging of accounts receivable at the date of the consolidated financial statements and assess collectibility based on historic results, current collection trends and an evaluation of economic conditions. If estimates are inaccurate, we may incur gains or losses that could have a material effect on our results of operations.
 


The allowance for doubtful accounts totaled $97 million at December 31, 2008. This amount includes a $38 million reduction inIn 2008, we reduced the carrying value of a receivable from SemCrude, L.P., a crude oil purchaser.purchaser, by $38 million. We recognizedreduced the carrying value by an associated pre-tax charge of $38additional $12 million during third quarter 2008.in 2009 when a settlement was reached and we received a distribution from SemCrude. See Item 8. Financial Statements and Supplementary Data—Data – Note 17 –17.  Commitments and Contingencies.
 
In addition, throughThrough December 31, 2008, we had recorded an allowance for doubtful accounts of $57 million related to our Ecuador power operations. The allowance was necessary to cover potentially uncollectible balances, as certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. As a result of pursuing various strategies to protect our interests, including international arbitration and litigation, we reached a settlement in fourth quarter 2008. However,In March and April 2009, we have not yet received any funds related tototal payments of $60 million in accordance with the settlement. We will reverse ourterms of the settlement, against which a reserve of $46 million had previously been recorded.  Accordingly, we reduced the allowance for doubtful accounts upon receiptby $46 million and included the amount as a reduction in electricity generation expense in first quarter 2009.


The allowance for doubtful accounts totaled $31 million at December 31, 2009. See Item 8. Financial Statements and Supplementary Data—Data – Note 2 –2. Summary of Significant Accounting Policies – Allowance for Doubtful Accounts.
 
Benefit Plans—We sponsor a qualified defined benefit pension plan, a non-qualified defined benefit pension plan (restoration plan), and other postretirement benefit plans. The actuarial determination of the projected benefit obligations and related benefit expense requires that certain assumptions be made regarding such variables as expected return on plan assets, discount rates, rates of future compensation increases, estimated future employee turnover rates and retirement dates, distribution election rates, mortality rates, retiree utilization rates for health care services and health care cost trend rates. The selection of assumptions requires considerable judgment concerning future events and has a significant impact on the amount of the obligations recorded in the consolidated balance sheets and on the amount of expense included in the consolidated statements of operations.
 
We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2008,2010, cumulative asset gains (losses) of approximately $3$(16) million remained to be recognized in the calculation of the market-related value of assets.
 
In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds invested or to be invested to provide for plan benefits included in the projected benefit obligations. This includes considering the returns being earned by the plan assets and the rates of return expected to be available for reinvestment. We assume that the long-term asset mix will be consistent with the target asset allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in asset allocation. A 1% decrease in the expected return on plan assets assumption would have increased 20082009 net periodic benefit cost by approximately $2 million. The fair value of plan assets was $132$172 million at December 31, 2008.2009. The expected return assumption used in the calculation of 20082009 net periodic benefit cost was 8.25%8.00%. The assumption will be reduced to 8.00%7.50% for the calculation of 20092010 net periodic benefit cost.
 
In selecting a discount rate, employers may look to rates of return on high quality fixed-income investments available as of the year-end measurement date and expected to be available during the period to maturity of the pension benefits. In order to determine an appropriate December 31, 20082009 discount rate, we performed an analysis of the Citigroup Pension Discount Curve (the CPDC) for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate assumption would have decreased 20082009 net periodic benefit cost by $2 million and decreased the benefit obligation for the combined plans by $20$22 million at December 31, 2008.2009. A 1% decrease in the discount rate assumption would have increased 20082009 net periodic benefit cost by $2 million and increased the benefit obligation for the combined plans by $24 million at December 31, 2008.2009. The assumed discount rate used to determine net periodic benefit cost for 20082009 was 6.50%6.00% for ourthe defined benefit pension and restoration plans and 6.25% for ourthe restoration and medical and life plans. The assumed discount rate used to determine the benefit obligations at December 31, 20082009 was 6.00% for ourthe defined benefit pension plan and 6.25%restoration plans and 5.50% for our restoration andthe medical and life plans. The total accrued benefit obligation for ourthe defined benefit pension, restoration and medical and life plans was $216$251 million at December 31, 2008.2009.
 
Recently Issued Pronouncements—See Item 8. Financial Statements and Supplementary Data—Note 18—Recently Issued Pronouncements.


Item 7A.  Quantitative and Qualitative Disclosures About Market Risk
 
Commodity Price Risk
 
Derivative Instruments Held for Non-Trading Purposes—Purposes   We are exposed to market risk in the normal course of business operations, and the uncertainty of crude oil and natural gas prices continues to impact the oil and gas industry. Due to the volatility of crude oil and natural gas prices, we continue to use derivative instruments as a means of managing our exposure to price changes.
 
At December 31, 2008,2009, we had entered into variable to fixed price commodity swaps, costless collars and basis swaps related to future crude oil and natural gas sales. Our open commodity derivative instruments were in a net receivablepayable position with a fair value of $445$103 million. Based on the December 31, 20082009 published forward commodity price curves, for the underlying commodities, a price increase of $1.00 per Bbl for crude oil would decreaseincrease the fair value of our net commodity derivative receivablepayable by approximately $9 million. A price increase of $0.10 per MMBtu for natural gas would decreaseincrease the fair value of our net commodity derivative receivablepayable by approximately $7$12 million.  Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 


As of December 31, 2008,2009, a net unrealized loss of $48$12 million, net of tax, is recorded in AOCL in the consolidated balance sheets.  We will reclassify $36 millionall of the remaining deferred loss to earnings during 20092010 as adjustments to revenue when the associated production occurs.  The remaining $12 million of deferred loss will be reclassified to earnings during 2010.
 
Interest Rate Risk
 
Changes in interest rates affect the amount of interest we pay on borrowings under our revolving credit facility and other variable-rate debt and the amount of interest we earn on our short-term investments.
 
At December 31, 2008,2009, we had $2.245$2 billion (excluding unamortized discount) of long-term debt outstanding. Of this amount, $639 million$1.6 billion was fixed-rate debt with a weighted average interest rate of 6.92%7.73%. Although near termnear-term changes in interest rates may affect the fair value of our fixed-rate debt, they do not expose us to the risk of earnings or cash flow loss.
 
The remainder of our long-term debt, $1.606 billion$382 million at December 31, 2008,2009, was variable-rate debt. We also had $25 million of short-term variable-rate debt at December 31, 2008. Variable-rate debt exposes us to the risk of earnings or cash flow loss due to increases in market interest rates. We estimate that a hypothetical 25 basis point change in the floating interest rates applicable to the December 31, 20082009 balance of our variable-rate debt would result in a change in annual interest expense of approximately $4$1 million.
 
We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense. At December 31, 2008,2009, AOCL included $3$2 million, net of tax, related to interest rate locks. This amount is currently being reclassified into earnings as adjustments to interest expense over the term of our 5¼% Senior Notes due April 2014. See Item 8. Financial Statements and Supplementary Data—Data – Note 6—6. Derivative Instruments and Hedging Activities.
 
We are also exposed to interest rate risk related to our short-term investments.interest-bearing cash and cash equivalents balances. As of December 31, 2008, 58% of2009, our cash was investedand cash equivalents totaled $1 billion with investments in US Treasury securities.money market funds and short-term deposits with major banking institutions. A hypothetical 25 basis point change in the floating interest rates applicable to the amount invested as of December 31, 2008 balance2009 would result in a change in annual interest income of approximately $2$2.5 million.
 
Foreign Currency Risk
 
We have not entered into foreign currency derivative instruments. The US dollar is considered the functional currency for each of our international operations. Substantially all of our international crude oil, natural gas and NGL production is sold pursuant to US dollar denominated contracts. Transactions, such as operating costs and administrative expenses that are completedpaid in a foreign currency, are remeasured into US dollars and recorded in the financial statements at prevailing currency exchange rates. We do not have any significantCertain monetary assets orand liabilities, denominated in a foreign currency other than oursuch as foreign deferred tax liabilities in certain foreign tax jurisdictions.jurisdictions, are denominated in a foreign currency. An increase in exchange rates between the US dollar and the currency of the foreign tax jurisdiction in which these liabilities are located could result in the use of additional cash to settle these liabilities. However, transactionTransaction gains or losses were not material in any of the periods presented and we do not believe we are currently exposed to any material risk of loss on this basis. Such gains or losses are included in other non-operating (income) expense, net in the consolidated statements of operations.
 
In the UK sector of our North Sea operations, significant future capital commitments and certain operating expenses are expected to be denominated in British pounds and/or the Euro. Therefore, our cash flows could be impacted by future changes in the exchange rate between the US dollar and the British pound and/or the Euro. We currently have no foreign currency derivative instruments outstanding. However, we may enter into foreign currency derivative instruments (such as forward contracts, collars or swap agreements) in the future in order to mitigate our foreign currency exchange risk.


Item 8.   Financial Statements and Supplementary Data

INDEX TO FINANCIAL STATEMENTS
 
Consolidated Financial Statements of Noble Energy, Inc.
 
Management’s Report on Internal Control over Financial Reporting
57
64
Report of Independent Registered Public Accounting Firm (Financial Statements)
58
65
Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting)
59
66
Consolidated Statements of Operations for eachEach of the three yearsYears in the period endedThree-Year Period Ended December 31, 20082009
60
67
Consolidated Balance Sheets as of December 31, 20082009 and 20072008
61
68
Consolidated Statements of Cash Flows for eachEach of the three yearsYears in the period endedThree-Year Period Ended December 31, 20082009
62
69
Consolidated Statements of Shareholders’ Equity for eachEach of the three yearsYears in the period endedThree-Year Period Ended December 31, 20082009
63
70
Consolidated Statements of Comprehensive Income for eachEach of the three yearsYears in the period endedThree-Year Period Ended December 31, 20082009
64
71
Notes to Consolidated Financial Statements
Note 1. Nature of Operations6572
Note 2. Summary of Significant Accounting Policies72
Note 3. Asset Impairments82
Note 4. Acquisitions and Divestitures 83
Note 5. Fair Value Measurements and Disclosures 83
Note 6. Derivative Instruments and Hedging Activities 85
Note 7. Capitalized Exploratory Well Costs 88
Note 8. Long-Term Debt 89
Note 9. Income Taxes 91
Note 10. Asset Retirement Obligations 93
Note 11. Equity Method Investments94
Note 12. Benefit Plans 95
Note 13. Stock-Based Compensation 100
Note 14. Earnings Per Share 103
Note 15. Segment Information 104
Note 16. Additional Shareholders' Equity Information106
Note 17. Commitments and Contingencies106
Supplemental Oil and Gas Information (Unaudited)
97
108
Supplemental Quarterly Financial Information (Unaudited)
107
118


 


 
Management’s Report on Internal Control over Financial Reporting
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our Chief Executive Officer and Chief Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of consolidated financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America.
 
Because of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the 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 processes may deteriorate.
 
As of December 31, 2008,2009, our management assessed the effectiveness of our internal control over financial reporting based on the criteria for effective internal control over financial reporting established in “Internal Control—Internal Control – Integrated Framework”, issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that we maintained effective internal control over financial reporting as of December 31, 2008,2009, based on those criteria. Management included in its assessment of internal control over financial reporting all consolidated entities.
 
KPMG LLP, the independent registered public accounting firm that audited our consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of internal control over financial reporting as of December 31, 20082009 which is included herein.
 
 Noble Energy, Inc.
 





Report of Independent Registered Public Accounting Firm


The Board of Directors and Shareholders
Noble Energy, Inc.:
 
We have audited the accompanying consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the related consolidated statements of operations, shareholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008.2009. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We did not audit the financial statements of the Alba Plant LLC (Alba), the investment in which, as discussed in Note 11 of the consolidated financial statements, is accounted for by the equity method of accounting. The Company’s investment in Alba at December 31, 2009 and 2008 and 2007 was $105.6$111 million and $142.5$106 million, respectively, and its equity in earnings of Alba was $118.4$66 million, $128.1$118 million, and $101.3$128 million for the years ended December 31, 2009, 2008, 2007, and 2006,2007, respectively. The financial statements of Alba were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Alba, is based solely on the reports of the other auditors.
 
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 audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits and the reports of other auditors provide a reasonable basis for our opinion.
 
In our opinion, based on our audits and the reports of the other auditors, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Noble Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2008,2009, in conformity with U.S. generally accepted accounting principles.
 
As discussed in Note 2 to the consolidated financial statements, effective December 31, 2006, the Company changed its method of accounting for defined benefit pension and other postretirement plans.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 18, 20092010 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
 
/s/ KPMG LLP
 
Houston, Texas
February 18, 20092010
 




 
 
Report of Independent Registered Public Accounting Firm
 
The Board of Directors and Shareholders
Noble Energy, Inc.:
 
We have audited Noble Energy, Inc.’s internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Noble Energy, Inc.’s management is responsible 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 an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit 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 audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
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 (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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.
 
In our opinion, Noble Energy, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2008,2009, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Noble Energy, Inc. and subsidiaries as of December 31, 20082009 and 2007,2008, and the related consolidated statements of operations, shareholders’ equity, comprehensive income, and cash flows for each of the years in the three-year period ended December 31, 2008,2009, and our report dated February 18, 20092010 expressed an unqualified opinion on those consolidated financial statements.
 
/s/ KPMG LLP
 
Houston, Texas
February 18, 20092010
 


Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Operations
 
(in millions, except per share amounts) 
          
  Year Ended December 31, 
  2008  2007  2006 
Revenues         
Oil, gas and NGL sales $3,651  $2,966  $2,701 
Income from equity method investees  174   211   139 
Other revenues  76   95   100 
Total  3,901   3,272   2,940 
             
Costs and Expenses            
Lease operating expense  371   322   317 
Production and ad valorem taxes  166   114   109 
Transportation expense  57   52   29 
Exploration expense  217   219   168 
Depreciation, depletion and amortization  791   736   633 
General and administrative  236   206   165 
Asset impairments  294   4   9 
Gain on sale of assets  (5)  (12)  (220)
Other operating expense, net  129   145   111 
Total  2,256   1,786   1,321 
Operating Income  1,645   1,486   1,619 
Other (Income) Expense            
(Gain) loss on commodity derivative instruments  (440)  (2)  392 
Interest, net of amount capitalized  69   113   117 
Other (income) expense, net  (45)  7   14 
Total  (416)  118   523 
Income Before Income Taxes  2,061   1,368   1,096 
Income Tax Provision  711   424   418 
Net Income $1,350  $944  $678 
             
Earnings Per Share            
Basic $7.83  $5.52  $3.86 
Diluted  7.58   5.45   3.79 
             
Weighted average number of shares outstanding            
Basic  173   171   176 
Diluted  176   173   179 
             
The accompanying notes are an integral part of these financial statements.         
Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Operations
 
(in millions, except per share amounts) 
          
  Year Ended December 31, 
  2009  2008  2007 
Revenues         
Oil, Gas and NGL Sales $2,060  $3,651  $2,966 
Income from Equity Method Investees  84   174   211 
Other Revenues  169   76   95 
Total Revenues  2,313   3,901   3,272 
Costs and Expenses            
Production Expense  525   594   488 
Exploration Expense  144   217   219 
Depreciation, Depletion and Amortization  816   791   736 
General and Administrative  237   236   206 
Asset Impairments  604   294   4 
Other Operating Expense, Net  45   134   124 
Total Operating Expenses  2,371   2,266   1,777 
Operating Income (Loss)
  (58)  1,635   1,495 
Other (Income) Expense            
(Gain) Loss on Commodity Derivative Instruments  110   (440)  (2)
Interest, Net of Amount Capitalized  84   69   113 
Other Non-Operating (Income) Expense, Net  12   (55)  16 
Total Other (Income) Expense  206   (426)  127 
Income (Loss) Before Income Taxes  (264)  2,061   1,368 
Income Tax Provision (Benefit)  (133)  711   424 
Net Income (Loss) $(131) $1,350  $944 
             
Earnings (Loss) Per Share, Basic $(0.75) $7.83  $5.52 
Earnings (Loss) Per Share, Diluted  (0.75)  7.58   5.45 
             
Weighted Average Number of Shares Outstanding, Basic  173   173   171 
Weighted Average Number of Shares Outstanding, Diluted  173   176   173 
             
The accompanying notes are an integral part of these financial statements.         
 

Noble Energy, Inc. 
Consolidated Balance Sheets
 
(in millions) 
       
  December 31, 
  2009  2008 
ASSETS 
Current Assets      
Cash and Cash Equivalents $1,014  $1,140 
Accounts Receivable, Net  465   423 
Commodity Derivative Assets, Current  13   437 
Other Current Assets  186   158 
Total Assets, Current  1,678   2,158 
Property, Plant and Equipment        
Oil and Gas Properties (Successful Efforts Method of Accounting)  12,584   11,963 
Property, Plant and Equipment, Other  240   175 
Total Property, Plant and Equipment, Gross  12,824   12,138 
Accumulated Depreciation, Depletion and Amortization  (3,908)  (3,134)
Total Property, Plant and Equipment, Net  8,916   9,004 
Goodwill  758   759 
Other Noncurrent Assets  455   463 
Total Assets $11,807  $12,384 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY 
Current Liabilities        
Accounts Payable - Trade $548  $579 
Other Current Liabilities  442   595 
Total Liabilities, Current  990   1,174 
Long-Term Debt  2,037   2,241 
Deferred Income Taxes, Noncurrent  2,076   2,174 
Other Noncurrent Liabilities  547   486 
Total Liabilities  5,650   6,075 
         
Commitments and Contingencies        
         
Shareholders’ Equity        
Preferred Stock - Par Value $1.00; 4 Million Shares Authorized, None Issued  -   - 
Common Stock - Par Value $3.33 1/3; 250 Million Shares Authorized; 194 Million and 192 Million Shares Issued, Respectively  645   641 
Additional Paid in Capital  2,260   2,193 
Accumulated Other Comprehensive Loss  (75)  (110)
Treasury Stock, at Cost; 19 Million Shares  (615)  (614)
Retained Earnings  3,942   4,199 
Total Shareholders’ Equity  6,157   6,309 
Total Liabilities and Shareholders’ Equity $11,807  $12,384 
         
The accompanying notes are an integral part of these financial statements.        

Noble Energy, Inc. 
Consolidated Statements of Cash Flows
 
(in millions) 
          
  Year Ended December 31, 
  2009  2008  2007 
Cash Flows From Operating Activities         
Net Income (Loss) $(131) $1,350  $944 
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities         
Depreciation, Depletion and Amortization  816   791   736 
Dry Hole Expense  11   84   90 
Asset Impairments  604   294   4 
Deferred Income Taxes  (296)  359   292 
Income from Equity Method Investees  (84)  (174)  (211)
Dividends from Equity Method Investees  92   221   227 
Unrealized (Gain) Loss on Commodity Derivative Instruments  606   (522)  (2)
Settlement of Previously Recognized Hedge Losses  -   (194)  (183)
Allowance for Doubtful Accounts  (18)  49   14 
Net Gain on Asset Sales  (22)  (5)  (12)
(Gain) Loss on Involuntary Conversion  (9)  9   51 
Other Adjustments for Noncash Items Included in Income  86   26   91 
Changes in Operating Assets and Liabilities            
(Increase) Decrease in Accounts Receivable  (28)  121   (22)
(Increase) Decrease in Other Current Assets  (4)  (17)  116 
Increase (Decrease) in Accounts Payable  (19)  (142)  19 
Increase (Decrease) in Other Current Liabilities  (38)  67   (158)
Increase (Decrease) in Other Operating Assets and Liabilities, Net  (58)  (32)  21 
Net Cash Provided by Operating Activities  1,508   2,285   2,017 
             
Cash Flows From Investing Activities            
Additions to Property, Plant and Equipment  (1,268)  (1,971)  (1,414)
Acquisitions, Net of Cash Acquired  -   (292)  - 
Proceeds from Sale of Property, Plant and Equipment, and Other  3   131   11 
Net Cash Used in Investing Activities  (1,265)  (2,132)  (1,403)
             
Cash Flows From Financing Activities            
Exercise of Stock Options  17   27   25 
Excess Tax Benefits from Stock-Based Awards  5   24   20 
Dividends Paid, Common Stock  (126)  (115)  (75)
Purchase of Treasury Stock  (1)  (3)  (102)
Proceeds from Credit Facilities  340   951   280 
Repayment of Credit Facilities  (1,564)  (525)  (255)
Proceeds from Issuance of Senior Long-Term Debt  989   -   - 
Repayment of Installment Note  (25)  (25)  - 
Repurchase of Senior Debentures  (4)  (7)  - 
Net Cash Provided by (Used in) Financing Activities  (369)  327   (107)
Increase (Decrease) in Cash and Cash Equivalents  (126)  480   507 
Cash and Cash Equivalents at Beginning of Period  1,140   660   153 
Cash and Cash Equivalents at End of Period $1,014  $1,140  $660 
             
The accompanying notes are an integral part of these financial statements.            
             


Noble Energy, Inc. 
Consolidated Statements of Shareholders' Equity
 
(in millions) 
          
  Year Ended December 31, 
  2009  2008  2007 
Common Stock         
Balance, Beginning of Period $641  $636  $629 
Exercise of Stock Options  2   4   5 
Restricted Stock Awards, Net  2   1   2 
Balance, End of Period  645   641   636 
Capital in Excess of Par Value            
Balance, Beginning of Period  2,193   2,106   2,041 
Stock-Based Compensation Expense  49   39   27 
Exercise of Stock Options  15   23   20 
Tax Benefits Related to Exercise of Stock Options  5   24   20 
Restricted Stock Awards, Net  (2)  (1)  (2)
Rabbi Trust Shares Sold  -   2   - 
Balance, End of Period  2,260   2,193   2,106 
Accumulated Other Comprehensive Loss            
Balance, Beginning of Period  (110)  (284)  (140)
Oil and Gas Cash Flow Hedges            
Realized Amounts Reclassified Into Earnings  36   207   33 
Unrealized Change in Fair Value  -   -   (184)
Net Change in Other  (1)  (33)  7 
Balance, End of Period  (75)  (110)  (284)
Treasury Stock at Cost            
Balance, Beginning of Period  (614)  (613)  (511)
Purchases of Treasury Stock  (1)  (3)  (102)
Rabbi Trust Shares Sold  -   2   - 
Balance, End of Period  (615)  (614)  (613)
Retained Earnings            
Balance, Beginning of Period  4,199   2,964   2,095 
Net Income (Loss)  (131)  1,350   944 
Cash Dividends ($0.720, $0.660 and $0.435 Per Share, Respectively)  (126)  (115)  (75)
Balance, End of Period  3,942   4,199   2,964 
             
Total Shareholders' Equity $6,157  $6,309  $4,809 
             
The accompanying notes are an integral part of these financial statements.            



Noble Energy, Inc. and Subsidiaries 
Consolidated Balance Sheets
 
(in millions) 
       
  December 31, 
  2008  2007 
ASSETS      
Current Assets      
Cash and cash equivalents $1,140  $660 
Accounts receivable, net  423   594 
Commodity derivative instruments  437   15 
Deferred income taxes  -   131 
Asset held for sale  26   82 
Other current assets  132   87 
Total current assets  2,158   1,569 
Property, plant and equipment:        
Oil and gas properties (successful efforts method of accounting)  11,963   10,217 
Other property, plant and equipment  175   112 
Total property, plant and equipment, net  12,138   10,329 
Accumulated depreciation, depletion and amortization  (3,134)  (2,384)
Total property, plant and equipment, net  9,004   7,945 
Goodwill  759   761 
Other noncurrent assets  463   556 
Total Assets $12,384  $10,831 
         
LIABILITIES AND SHAREHOLDERS’ EQUITY        
Current Liabilities        
Accounts payable - trade $579  $781 
Income taxes payable  130   52 
Commodity derivative instruments  23   540 
Deferred income taxes  142   - 
Other current liabilities  300   263 
Total current liabilities  1,174   1,636 
Long-term debt  2,241   1,851 
Deferred income taxes  2,174   1,984 
Other noncurrent liabilities  486   551 
Total Liabilities  6,075   6,022 
         
Commitments and Contingencies        
         
Shareholders’ Equity        
Preferred stock - par value $1.00; 4 million shares authorized, none issued  -   - 
Common stock - par value $3.33 1/3; 250 million shares authorized;        
192 million and 191 million shares issued, respectively  641   636 
Capital in excess of par value  2,193   2,106 
Accumulated other comprehensive loss  (110)  (284)
Treasury stock, at cost: 19 million shares  (614)  (613)
Retained earnings  4,199   2,964 
Total Shareholders’ Equity  6,309   4,809 
Total Liabilities and Shareholders’ Equity $12,384  $10,831 
         
The accompanying notes are an integral part of these financial statements.        
Noble Energy, Inc. 
Consolidated Statements of Comprehensive Income
 
(in millions) 
          
          
  Year Ended December 31, 
  2009  2008  2007 
Net Income (Loss) $(131) $1,350  $944 
Other Items of Comprehensive Income (Loss)            
Oil and Gas Cash Flow Hedges            
Realized Losses Reclassified Into Earnings  58   331   54 
Less Tax Benefit
  (22)  (124)  (21)
Unrealized Change in Fair Value  -   -   (295)
Less Tax Benefit  -   -   111 
Net Change in Other  (2)  (52)  11 
Less Tax Provision (Benefit)  1   19   (4)
Other Comprehensive Income (Loss)  35   174   (144)
Comprehensive Income (Loss) $(96) $1,524  $800 
             
The accompanying notes are an integral part of these financial statements.         
 


Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Cash Flows
 
(in millions) 
  Year Ended December 31, 
  2008  2007  2006 
Cash Flows from Operating Activities         
Net income $1,350  $944  $678 
Adjustments to reconcile net income to net cash provided by operating activities:            
Depreciation, depletion and amortization  791   736   633 
Dry hole expense  84   90   70 
Impairment of assets  294   4   9 
Gain on sale of assets  (5)  (12)  (220)
Deferred income taxes  359   292   194 
Income from equity method investees  (174)  (211)  (139)
Dividends from equity method investees  221   227   37 
Unrealized (gain) loss on commodity derivative instruments  (522)  (2)  9 
Settlement of previously recognized hedge losses  (194)  (183)  406 
Allowance for doubtful accounts  49   14   19 
Loss on involuntary conversion  9   51   - 
Other  26   91   82 
Changes in operating assets and liabilities, net of acquisition:     
Decrease (increase) in accounts receivable  121   (22)  (32)
(Increase) decrease in other current assets  (37)  8   (5)
Decrease in probable insurance claims  20   108   140 
(Decrease) increase in accounts payable  (142)  19   (11)
Increase (decrease) in other current liabilities  35   (137)  (140)
Net Cash Provided by Operating Activities  2,285   2,017   1,730 
             
Cash Flows From Investing Activities            
Additions to property, plant and equipment  (1,971)  (1,414)  (1,357)
Acquisitions, net of cash acquired  (292)  -   (412)
Proceeds from sale of property, plant and equipment  131   9   520 
Distributions from equity method investees, net  -   2   151 
Net Cash Used in Investing Activities  (2,132)  (1,403)  (1,098)
             
Cash Flows From Financing Activities            
Exercise of stock options  27   25   63 
Excess tax benefits from stock-based awards  24   20   26 
Cash dividends paid  (115)  (75)  (49)
Purchase of treasury stock  (3)  (102)  (399)
Proceeds from credit facilities  951   280   480 
Repayment of credit facilities  (525)  (255)  (605)
Repurchase of senior debentures  (7)  -   - 
Repayment of installment notes  (25)  -   - 
Repayment of term loans  -   -   (105)
Net Cash Provided by (Used in) Financing Activities  327   (107)  (589)
Increase in Cash and Cash Equivalents  480   507   43 
Cash and Cash Equivalents at Beginning of Period  660   153   110 
Cash and Cash Equivalents at End of Period $1,140  $660  $153 
             
             
The accompanying notes are an integral part of these financial statements. 
             



Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Shareholders' Equity
 
(in millions) 
          
          
  Year Ended December 31, 
  2008  2007  2006 
Common Stock         
Balance, beginning of year $636  $629  $616 
Exercise of stock options  4   5   13 
Restricted stock awards, net  1   2   - 
Balance, end of year  641   636   629 
Capital in Excess of Par Value            
Balance, beginning of year  2,106   2,041   1,945 
Stock-based compensation expense  39   27   12 
Exercise of stock options  23   20   50 
Tax benefits related to exercise of stock options  24   20   26 
Restricted stock awards, net  (1)  (2)  - 
Rabbi trust shares sold  2   -   13 
Adoption of SFAS 123(R), net of tax  -   -   (5)
Balance, end of year  2,193   2,106   2,041 
Accumulated Other Comprehensive Loss            
Balance, beginning of year  (284)  (140)  (784)
Oil and gas cash flow hedges:            
Realized amounts reclassified into earnings  207   33   145 
Unrealized amounts reclassified into earnings  -   -   265 
Unrealized change in fair value  -   (184)  250 
Net change in other  (33)  7   17 
Adoption of SFAS 158, net of tax  -   -   (33)
Balance, end of year  (110)  (284)  (140)
Treasury Stock at Cost            
Balance, beginning of year  (613)  (511)  (148)
Purchases of treasury stock  (3)  (102)  (399)
Rabbi trust shares sold  2   -   36 
Balance, end of year  (614)  (613)  (511)
Deferred Compensation - Restricted Stock            
Balance, beginning of year  -   -   (5)
Adoption of SFAS 123(R), net of tax  -   -   5 
Balance, end of year  -   -   - 
Retained Earnings            
Balance, beginning of year  2,964   2,095   1,466 
Net income  1,350   944   678 
Cash dividends ($0.660, $0.435, and $0.275 per share, respectively)  (115)  (75)  (49)
Balance, end of year  4,199   2,964   2,095 
             
Total Shareholders' Equity $6,309  $4,809  $4,114 
             
The accompanying notes are an integral part of these financial statements. 
63
Noble Energy, Inc. and Subsidiaries 
Consolidated Statements of Comprehensive Income
 
(in millions) 
          
  Year Ended December 31, 
  2008  2007  2006 
Net income $1,350  $944  $678 
Other items of comprehensive income (loss)            
Oil and gas cash flow hedges:            
Realized amounts reclassified into earnings  331   54   232 
Less tax provision  (124)  (21)  (87)
Unrealized change in fair value  -   (295)  352 
Less tax provision  -   111   (102)
Unrealized amounts reclassified into earnings  -   -   424 
Less tax provision  -   -   (159)
Net change in other  (52)  11   25 
Less tax provision  19   (4)  (8)
Other comprehensive income (loss)  174   (144)  677 
Comprehensive income $1,524  $800  $1,355 
             
The accompanying notes are an integral part of these financial statements.         


Noble Energy, Inc.
Notes to Consolidated Financial Statements


 
Note 1—1.  Nature of Operations
 
Noble Energy, Inc. (Noble Energy, we or us) is an independent energy company engaged in worldwide crude oil, natural gas and natural gas liquids (NGLs) exploration and production. We operate primarily in the Rocky Mountains, Mid-continent, and deepwater Gulf of Mexico areas in the US, with key international operations offshore Israel the North Sea and West Africa.
 
Note 2—2.  Summary of Significant Accounting Policies
 
Basis of Presentation and Consolidation—Consolidation  Accounting policies used by us and our subsidiaries conform to accounting principles generally accepted in the US. Significant policies are discussed below. Our consolidated accounts include our accounts and the accounts of our wholly-owned subsidiaries. We use the equity method of accounting for investments in entities that we do not control but over which we exert significant influence. We carry equity method investments at our share of net assets of the equity investees plus our loans and advances. Differences in the basis of the investment and the separate net asset value of the investee, if any, are amortized into income over the remaining useful life of the underlying assets. See Note 11—11. Equity Method Investments.  All significant intercompany balances and transactions have been eliminated upon consolidation.
 
Use of Estimates—The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the US (GAAP) requires us to make a number of estimates and assumptions relating to the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period.
 
Estimates of crude oil and natural gas reserves are the most significant of our estimates. All of the reservereserves data in this Form 10-K are estimates. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas. There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. The accuracy of any reservereserves estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. As a result, reservereserves estimates may be different from the quantities of crude oil and natural gas that are ultimately recovered. EngineersQualified petroleum engineers in our Houston, Denver and London offices prepare all reservereserves estimates for our different geographical regions. These reservereserves estimates are reviewed and approved by senior engineering staff and division management with final approval by the vice president in charge of corporate reservesVice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. See Supplemental Oil and Gas Information.Information (Unaudited).
 
Other items subject to estimates and assumptions include the carrying amounts of property, plant and equipment and goodwill, asset retirement obligations, valuation allowances for receivables and deferred income tax assets, valuation of derivative instruments, and obligations related to employee benefits, among others. Management evaluates estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. The current illiquidCurrent credit market conditions combined with volatile commodity prices hashave resulted in increased uncertainty inherent in such estimates and assumptions. As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.
 
Reclassification—Reclassification Certain reclassifications have been made to the 20072008 and 20062007 consolidated financial statements to conform to the 20082009 presentation. These reclassifications were not material to the financial statements.
 
Property, Plant and Equipment—EquipmentSignificant accounting policies for our property, plant and equipment are as follows:
 
Successful Efforts Method—We account for crude oil and natural gas properties under the successful efforts method of accounting. Under this method, costs to acquire mineral interests in crude oil and natural gas properties, to drill and equip exploratory wells that find proved reserves and to drill and equip development wells are capitalized. Capitalized costs of producing crude oil and natural gas properties, along with support equipment and facilities, are amortized to expense by the unit-of-production method based on proved crude oil and natural gas reserves on a field-by-field basis as estimated by our engineers. Our policy is to use quarter-end reserves and add back current period production to compute quarterly DD&A expense. Costs of certain gathering facilities or processing plants serving a number of properties or used for third partythird-party processing are depreciated using the straight-line method over the useful lives of the assets ranging from 7five to 14 years. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Repairs and maintenance are expensed as incurred.
 
Proved Property Impairment—In accordance with SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets,” weWe review proved oil and gas properties and other long-lived assets for impairment when events and circumstances indicate a decline in the recoverability of the carrying value of such properties, such as a downward revision of the reservereserves estimates or sustained decrease in commodity prices. We estimate the future cash flows expected in connection with the properties and compare such future cash flows to the carrying amount of the properties to determine if the carrying amount is recoverable. When the carrying amounts of the properties exceed their estimated undiscounted future cash flows, the carrying amount of the properties is reduced to their estimated fair value. The factors used to determine fair value include, but are not limited to, estimates of proved reserves, available market data associated with the property or similar properties, future commodity prices and operating expenses, timing of future production, future capital expenditures and a risk-adjusted discount rate.
 

6572
Noble Energy, Inc.
Notes to Consolidated Financial Statements


During
Due to the declines in commodity prices which occurred during fourth quarter 2008 due to declinesand continued in commodity prices,first quarter 2009, we assessed the recoverability of our proved oil and gas properties and other long-lived assets and recorded impairment charges. Additional impairment charges were recorded at December 31, 2009. See Note 3 –3.  Asset Impairments. In 2007, we recorded impairment charges of $4 million, primarily related to downward reserve revisions on US properties and/or adjustment of the carrying value of properties to their fair values. It is reasonably possible that other proved oil and gas properties or long-lived assets could become impaired in the future if commodity prices continue to decline.
We recorded impairments of $4 million in 2007 and $9 million in 2006, primarily related to downward reserve revisions on US properties and/or adjustment of the carrying value of properties to their fair values.
 
Unproved Property Impairment—We assess individually significant unproved properties for impairment of value on a quarterly basis and recognize a loss at the time of impairment by providing an impairment allowance. In determining whether a significant unproved property is impaired we consider numerous factors including, but not limited to, current exploration plans, favorable or unfavorable exploratory activity on the property being evaluated and/or adjacent leaseholds,properties, our geologists' evaluation of the lease,property, and the remaining months in the lease term.term for the property.
 
When we have allocated fair values to a significant unproved property as the result of a business combination or other purchase of proved and unproved properties, we use a future cash flow analysis to assess the property for impairment. Cash flows used in the impairment analysis are determined based on management’s estimates of crude oil and natural gas reserves, future commodity prices and future costs to extract the reserves. Cash flow estimates related to probable and possible reserves are reduced by additional risk-weighting factors. Other individually insignificant unproved properties are amortized on a composite method based on our experience of successful drilling and average holding period.
 
During fourth quarter 2008, due to declines in commodity prices, we assessed the recoverability of our individually significant unproved oil and gas properties and recorded impairment charges. See Note 3 –3.  Asset Impairments. In 2009, no impairment charges were recorded. In 2007, we recorded $3 million of impairment charges for individually significant unproved properties and included the amounts in exploration expense. It is reasonably possible that other individually significant unproved oil and gas properties could become impaired in the future if commodity prices continue to decline.
We recorded impairments of individually significant unproved properties of $3 million in 2007 and $1 million in 2006 and included the amounts in exploration expense.
 
Properties Acquired in Business Combinations—In determining the fair values of proved and unproved properties acquired in business combinations, we prepare estimates of crude oil and natural gas reserves. We estimate future prices to apply to the estimated reservereserves quantities acquired, and estimate future operating and development costs, to arrive at estimates of future net cash flows. For the fair value assigned to proved reserves, the future net cash flows are discounted using a market-based weighted average cost of capital rate determined appropriate at the time of the business combination. To compensate for the inherent risk of estimating and valuing unproved reserves, the discounted future net cash flows of probable and possible reserves are reduced by additional risk-weighting factors.
 
Exploration Costs—Geological and geophysical costs, delay rentals, amortization of unproved leasehold costs, and costs to drill exploratory wells that do not find proved reserves are expensed as oil and gas exploration. We carry the costs of an exploratory well as an asset if the well finds a sufficient quantity of reserves to justify its capitalization as a producing well and as long as we are making sufficient progress assessing the reserves and the economic and operating viability of the project. For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take us more than one year to evaluate the future potential of the exploration well and make a determination of its economic viability. Our ability to move forward on a project may be dependent on gaining access to transportation or processing facilities or obtaining permits and government or partner approval, the timing of which is beyond our control. In such cases, exploratory well costs remain suspended as long as we are actively pursuing access to necessary facilities and access to such permits and approvals and believe they will be obtained. We assess the status of suspended exploratory well costs on a quarterly basis. See Note 7—7. Capitalized Exploratory Well Costs.
 
Other Property—Other property includes autos,automobiles, trucks, airplane, office furniture and computer equipment and other fixed assets such as building and leasehold improvements. These items are recorded at cost and are depreciated on the straight-line method based on expected lives of the individual assets or group of assets, which range from three to ten years.
 

66

Capitalization of Interest—We capitalize interest costs associated with the development and construction of significant properties or projects to bring them to a condition and location necessary for their intended use, which for crude oil and natural gas assets is at first production from the field. Interest is capitalized using an interest rate equivalent to the average rate we pay on long-term debt, including the credit facility and bonds. Capitalized interest is included in the cost of oil and gas assets and amortized with other costs on a unit-of-production basis. Capitalized interest totaled $45 million in 2009, $33 million in 2008, and $17 million in 2007, and $13 million in 2006.2007.
 
Revenue Recognition and Imbalances—We record revenues from the sales of crude oil, natural gas and NGLs when the product is delivered at a fixed or determinable price, title has transferred and collectibility is reasonably assured.
 

73
Noble Energy, Inc.
Notes to Consolidated Financial Statements


When we have an interest with other producers in properties from which natural gas is produced, we use the entitlements method to account for any imbalances. Imbalances occur when we sell more or less product than we are entitled to under our ownership percentage. Revenue is recognized only on the entitlement percentage of volumes sold. Any amount that we sell in excess of our entitlement is treated as a liability and is not recognized as revenue. Any amount of entitlement in excess of the amount we sell is recognized as revenue and a receivable is accrued.
 
Revenues derived from electricity generation are recognized when power is transmitted or delivered, the price is fixed and determinable and collectibility is reasonably assured.
 
We also engage in the purchase and sale of third-party crude oil and natural gas. We record third-party sales, net of cost of goods sold, as gathering, marketing and processing revenues when the product is delivered or the contract is net settled at a fixed or determinable price, title has transferred and collectibility is reasonably assured. Gathering, marketing and processing revenues are included in other revenues in the consolidated statements of operations.
 
Fair Value Measurements   US GAAP for fair value measurements establishes a fair value hierarchy which prioritizes the inputs to valuation techniques used to measure fair value into three levels. The fair value hierarchy gives the highest priority to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value. See Note 5. Fair Value Measurements and Disclosures.
Derivative Instruments and Hedging Activities—We use various derivative instruments in connection with anticipated   In order to reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, saleswe enter into crude oil and natural gas price hedging arrangements with respect to minimize the impacta portion of commodity price fluctuations. Suchour expected production. The derivative instruments we use include variable to fixed price commodity swaps, costless collars and variable to fixed price basis swaps. We account for derivative instruments and hedging activities in accordance with SFAS No. 133, “AccountingUS GAAP for Derivative Instrumentsderivative instruments and Hedging Activities, as amended” (SFAS 133). SFAS 133 established accounting and reporting standards requiring everyhedging activities. All derivative instrumentinstruments (including certain derivative instruments embedded in other contracts) tomust be recorded on the balance sheet as either an asset or liability measured at fair value. SFAS 133 requires that changesChanges in thea derivative instrument’s fair value must be recognized currently in earnings unless the derivative instrument has been designated as a cash flow hedge and specific cash flow hedge accounting criteria are met. Under cash flow hedge accounting, unrealized gains and losses are reflected in shareholders’ equity as AOCL until the forecasted transaction occurs. The derivative’s gains andor losses are then offset against related results on the hedged transaction in the statements of operations. Gains and losses from derivative instruments related to future crude oil and natural gas sales and which qualify for hedge accounting treatment are recorded in oil and gas sales in the consolidated statements of operations upon sale of the associated commodity.
 
SFAS 133 also requires that aA company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Only derivative instruments that are expected to be highly effective in offsetting anticipated gains or losses on the hedged cash flows and that are subsequently documented to have been highly effective can qualify for hedge accounting. Effectiveness must be assessed both at inception of the hedge and on an ongoing basis. Any ineffectiveness in hedging instruments whereby gains or losses do not exactly offset anticipated gains or losses of hedged cash flows is measured and recognized in earnings in the period in which it occurs. When using hedge accounting, we assess hedge effectiveness quarterly based on total changes in the derivative instrument’s fair value and using regression analysis. A hedge is considered effective if certain statistical tests are met. We record hedge ineffectiveness in (gain) loss on commodity derivative instruments. See Note 6—6. Derivative Instruments and Hedging Activities.
 
Through December 31, 2007, we elected to designate the majority of our crude oil and natural gas derivative instruments as cash flow hedges. Effective January 1, 2008, we voluntarily discontinued cash flow hedge accounting on all existing commodity derivative instruments. We voluntarily made this change to provide greater flexibilitysimplify the accounting for our commodity hedge program as well as to add more transparency in related disclosures for the benefit of our use of derivative instruments.investors.  From January 1, 2008 forward, we recognize all gains and losses on such instruments in earnings in the period in which they occur. Net derivative losses that were deferred in AOCL as of December 31, 2007, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur. The discontinuance of cash flow hedge accounting for commodity derivative instruments did not affect our net assets or cash flows at December 31, 2007 and doesdid not require adjustments to our previously reported financial statements.

67

Goodwill—GoodwillGoodwill represents the excess of the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. We account for goodwill in accordance with SFAS No. 142, “Goodwill and Other Intangible Assets” (SFAS 142). Goodwill is not amortized to earnings but is tested annually duringin the fourth quarter or whenever events or changes in circumstances indicate that the carrying value may not be recoverable. No goodwill impairment was indicated as of December 31, 2008.2009. However, it is reasonably possible that goodwill could become impaired in the future if commodity prices continue to decline. Changes in the carrying amount of goodwill are as follows:or other economic factors become less favorable.
 
  Year Ended December 31, 
  2008  2007 
  (in millions) 
Balance, beginning of period $761  $781 
Tax adjustments related to acquisitions  -   (15)
Tax benefits on stock options exercised  (2)  (5)
Balance, end of period $759  $761 
We reducereduced the amount of goodwill originally recorded by $1 million in 2009 and $2 million in 2008 for deferred tax assets associated with the exercise of fully-vested stock options assumed in conjunction with the Patina MergerMerger. Reductions are recorded to the extent that the stock-based compensation expense reported for tax purposes does not exceed the fair value of the awards recognized as part of the total purchase price. In 2010, the remainder of these options will expire and will no longer have an impact on our goodwill.

74
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Stock-Based Compensation We recognize the grant-date fair value of stock options and other stock-based compensation issued to employees in the statement of operations. Expense is recognized on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award). See Note 13. Stock-Based Compensation.
 
Income Taxes—TaxesIncome taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized when items of income and expense are recognized in the financial statements in different periods than when recognized in the applicable tax return. Deferred tax assets arise when expenses are recognized in the financial statements before the tax returns or when income items are recognized in the tax return prior to the financial statements. Deferred tax assets also arise when operating losses or tax credits are available to offset tax payments due in future years. Deferred tax liabilities arise when income items are recognized in the financial statements before the tax returns or when expenses are recognized in the tax return prior to the financial statements. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the date when the change in the tax rate was enacted.
 
StatementStatements of Operations Information- InformationAdditional statementstatements of operations information is as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Other Revenues         
Electricity sales (1)
 $56  $71  $72 
Gathering, marketing and processing  20   24   28 
Total $76  $95  $100 
Other Operating Expense, net            
Electricity generation(1)
 $57  $57  $59 
Gathering, marketing and processing  19   17   19 
Loss on involuntary conversion of assets (2)
  9   51   - 
Other operating (income) expense, net (3)
  44   20   33 
Total $129  $145  $111 
Other Expense, net            
Deferred compensation (income) expense (4)
 $(32) $33  $16 
Interest income  (20)  (19)  (3)
Other (income) expense, net  7   (7)  1 
Total $(45) $7  $14 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Other Revenues         
Refund of Deepwater Gulf of Mexico Royalties (1)
 $86  $-  $- 
Electricity Sales (2)
  72   56   71 
Gathering, Marketing and Processing (GMP) Revenues  11   20   24 
Total $169  $76  $95 
Production Expense            
Lease Operating Expense $372  $371  $322 
Production and Ad Valorem Taxes  94   166   114 
Transportation Expense  59   57   52 
Total $525  $594  $488 
Other Operating (Income) Expense, Net            
Net Gain on Asset Sales (3)
 $(22) $(5) $(12)
Electricity Generation Expense (2)
  18   57   57 
GMP Expense  18   19   17 
Settlement of Legal Proceedings (4)
  9   1   (1)
(Gain) Loss on Involuntary Conversion (5)
  (9)  9   51 
Other, Net (6)
  31   53   12 
Total $45  $134  $124 
Other Non-Operating (Income) Expense, Net            
Deferred Compensation (Income) Expense (7)
 $23  $(32) $33 
Interest Income (8)
  (13)  (20)  (19)
Other (Income) Expense, Net  2   (3)  2 
Total $12  $(55) $16 
 
(1)
See Refund of Deepwater Gulf of Mexico Royalties below.
(2)
Includes amounts related to our 100%-owned Ecuador integrated power project. The project includes the Amistad natural gas field, offshore Ecuador, which supplies natural gas to fuel the Machala power plant located in Machala, Ecuador. Electricity generation expense includes all operating and non-operating expenses associated with the plant, including DD&A and increaseschanges in the allowance for doubtful accountsaccounts. We recognized a net decrease of $32 million in the allowance in 2009, and net increases of $11 million in 2008 and $14 million in 2007 and $15 million in 2006.2007. See Allowance for Doubtful Accounts below.
(2)See Note 4 – Acquisitions and Divestitures – Main Pass Asset.
(3)
Includes $38$24 million write-downgain on sale of SemCrude, L.P. receivableour interest in thirdArgentina. In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million.  Recognition of the gain on the sale was deferred until second quarter 2008. See Note 17 – Commitments and Contingencies.
2009 when the Argentine government approved the sale.
(4)
Amount represents increases (decreases) in the fair valueThe amount for 2009 includes a $19 million charge on legal settlement, offset by a $15 million gain on legal settlement related to reimbursement of Noble Energy common stock held in a rabbi trust. See Note 12 – Benefit Plans.
bonuses paid for federal leases offshore California.

6875
Noble Energy, Inc.
Notes to Consolidated Financial Statements


(5)The amount for 2009 represents receipt of insurance claims related to Hurricanes Katrina and Rita damage. The amount for 2008 represents interim settlement of the replacement cost portion of the Hurricane Katrina insurance claim. The amount for 2007 represents project costs in excess of certain insurance coverage limitations related to hurricane cleanup costs at our Gulf of Mexico Main Pass asset.
(6)
Includes write-downs of SemCrude L.P. (SemCrude) receivable of $12 million in 2009 and $38 million in 2008. SemCrude was a purchaser of our crude oil. See Allowance for Doubtful Accounts below and Note 17. Commitments and Contingencies.
(7)The amount represents increases (decreases) in the fair value of shares of our common stock held in a rabbi trust. See Note 12. Benefit Plans.
(8)
Includes $11 million interest income related to expected refund of deepwater Gulf of Mexico royalties. See Refund of Deepwater Gulf of Mexico Royalties below.
Balance Sheet Information – Additional balance sheet information is as follows:
 
  December 31, 
  2009  2008 
(millions)      
Accounts Receivable, Net      
Commodity Sales $205  $296 
Joint Interest Billings  140   87 
Refund of Deepwater Gulf of Mexico Royalties (1)
  97   - 
Marketing and Trading Activities  25   130 
Other  29   7 
Allowance for Doubtful Accounts (2)
  (31)  (97)
Total $465  $423 
Other Current Assets        
Inventories, Current $89  $105 
Prepaid Expenses and Other Assets, Current  65   27 
Deferred Income Taxes, Net, Current  32   - 
Asset Held for Sale (3)
  -   26 
Total $186  $158 
Other Noncurrent Assets        
Equity Method Investments $303  $311 
Mutual Fund Investments  108   84 
Commodity Derivative Assets, Noncurrent  1   33 
Other Assets, Noncurrent  43   35 
Total $455  $463 
(1)
See Refund of Deepwater Gulf of Mexico Royalties below.
(2)See Allowance for Doubtful Accounts below.
(3)
Our remaining non-core Gulf of Mexico shelf asset at Main Pass was reclassified from held-for-sale to held-and-used and impaired during first quarter 2009. See Note 3. Impairments and Note 4. Acquisitions and Divestitures.

76
Noble Energy, Inc.
Notes to Consolidated Financial Statements

  December 31, 
  2008  2007 
  (in millions) 
Other Current Assets      
Inventories $105  $60 
Prepaid expenses and other  27   27 
Total $132  $87 
Other Noncurrent Assets        
Equity method investments $311  $357 
Mutual fund investments  84   124 
Commodity derivative instruments  33   5 
Other assets  35   70 
Total $463  $556 
Other Current Liabilities        
Accrued and other current liabilities $215  $207 
Short-term borrowings  25   25 
Asset retirement obligations  27   13 
Interest payable  9   18 
Deferred gain on asset sale  24   - 
Total $300  $263 
Other Noncurrent Liabilities        
Deferred compensation liabilities $159  $225 
Commodity derivative instruments  2   83 
Asset retirement obligations  184   131 
Accrued benefit costs  81   51 
Other noncurrent liabilities  60   61 
Total $486  $551 
  December 31, 
  2009  2008 
(millions)      
Accounts Payable - Trade      
Capital Costs $277  $273 
Royalties Payable  65   81 
Marketing and Trading Activities  76   159 
Lease Operating Expense  27   10 
Other  103   56 
Total $548  $579 
Other Current Liabilities        
Production and Ad Valorem Taxes $103  $114 
Commodity Derivative Liabilities, Current  100   23 
Income Taxes Payable  60   130 
Deferred Income Taxes, Net, Current  1   142 
Asset Retirement Obligations, Current  51   27 
Interest Payable  37   9 
Short-Term Borrowings  -   25 
Deferred Gain on Asset Sale, Current (1)
  -   24 
Other  90   101 
Total $442  $595 
Other Noncurrent Liabilities        
Deferred Compensation Liabilities, Noncurrent $213  $159 
Asset Retirement Obligations, Noncurrent  181   184 
Accrued Benefit Costs, Noncurrent  77   81 
Commodity Derivative Liabilities, Noncurrent  17   2 
Other  59   60 
Total $547  $486 
(1)
See footnote (3) to Statements of Operations Information above.
 
Statements of Cash Flows and Supplementary Disclosures of Cash Flow Information—Information For purposes of reporting cash flows, cash and cash equivalents include unrestricted cash on hand and investments with original maturities of three months or less at the time of purchase. Additional cash flow information is as follows:
 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Cash Paid During the Year For         
Interest, Net of Amount Capitalized $52  $76  $105 
Income Taxes Paid, Net  227   263   149 
Non-Cash Financing and Investing Activities            
Increase in Long-Term Obligation Related to FPSO Construction  29   -   - 
Issuance of Notes for Property Interests  -   -   50 
Refund of Deepwater Gulf of Mexico Royalties  On October 5, 2009, the US Supreme Court denied a petition filed by the US Department of the Interior (DOI) in a case styled Dept. of Interior, et al v. Kerr-McGee Oil and Gas Corp. (09-54).  This case involved the payment of royalties attributable to federal leases acquired by Kerr-McGee Oil and Gas Corporation (Kerr-McGee) pursuant to Section 304 of the Outer Continental Shelf Deep Water Royalty Relief Act of 1995 (DWRRA).  As a result of the Supreme Court’s decision, lower court rulings from the US District Court of the Western District of Louisiana and US Court of Appeals for the Fifth Circuit, which were in favor of Kerr-McGee, were left to stand.  Those courts ruled that the DOI did not have the authority to impose price thresholds that required the payment of royalties before minimum royalty suspension volumes imposed by Section 304 of the DWRRA were produced.
Based upon our analysis of the Kerr-McGee case, we believe that the Supreme Court’s decision impacts other companies, including us, who were not directly involved in the case but, like Kerr-McGee, acquired leases issued pursuant to Section 304 of the DWRRA.  As a result, we believe that we are entitled to a refund of approximately $86 million plus interest of $11 million. The refund is attributable to royalties that we previously paid on production of approximately 900 MBbls of crude oil and 3,000 MMcf of natural gas that were produced from January 1, 2003 through July 31, 2009. We have requested a refund from the MMS and anticipate receiving the refund in 2010.

77
Noble Energy, Inc.
Notes to Consolidated Financial Statements

  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Cash paid during the year for         
Interest, net of amount capitalized $76  $105  $106 
Income taxes paid, net  263   149   115 
Non-cash financing and investing activities            
Issuance of notes for property interests  -   50   - 

Allowance for Doubtful Accounts—AccountsWe routinely assess the recoverability of all material trade and other receivables to determine their collectibility. We accrue a reserve on a receivable when, based on management’s judgment, it is probable that a receivable will not be collected and the amount of such reserve may be reasonably estimated.
Changes in the allowance for doubtful accounts arewere as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Balance, beginning of period $50  $35  $19 
Charged to expense  49   14   19 
Deductions and other  (2)  1   (3)
Balance, end of period $97  $50  $35 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Balance, Beginning of period $97  $50  $35 
Changes            
Allowance for SemCrude receivable  12   38   - 
Allowance for Ecuador receivable  14   11   14 
Recovery of Ecuador receivable  (46)  -   - 
Other Changes  2   -   - 
Net Changes Before Write-offs  (18)  49   14 
Write-off of SemCrude receivable  (49)  -   - 
Other Write-offs  1   (2)  1 
Balance, End of Period $31  $97  $50 
 
During third quarter 2008, we increasedFor a discussion of the allowance by $38 million for the probable loss on a receivable from SemCrude L.P., a crude oil purchaser. Seematter, see Note 17 -17. Commitments and Contingencies.
 

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Through December 31, 2008, we had recorded an allowance for doubtful accounts of $57 million related to our Ecuador power operations. The allowance was necessary to cover potentially uncollectible balances, as certain entities purchasing electricity in Ecuador have been slow to pay amounts due us. As a result of pursuing various strategies to protect our interests, including international arbitration and litigation, we reached a settlement in fourth quarter 2008. However,In March and April 2009, we have not yet received any funds related tototal payments of $60 million in accordance with the settlement. We will reverse ourterms of the settlement, against which a reserve of $46 million had previously been recorded.  Accordingly, we reduced the allowance for doubtful accounts upon receiptby $46 million and included the amount as a reduction in electricity generation expense in first quarter 2009. We recorded an additional allowance of payment from the Ecuadorian government.
Amounts charged to expense include $11 million in 2008, $14 million in 2007 and $15 million in 2006 to cover potentially uncollectible balances related to the Ecuador power operations. The allowance was also increased by $2 millioncurrent period electricity sales in 2006 to record various provisions related to our US business.2009.
 
Inventories—Inventories Inventories consist primarily of tubular goods and production equipment used in our oil and gas operations and crude oil produced but not yet sold. Materials and supplies inventories are stated at the lower of average cost or market. The cost of crude oil inventory includes production costs and DD&A expense.
Inventories consisted of the following at December 31, 2008:following:
 
  December 31, 
  2008  2007 
  (in millions) 
Materials and supplies $92  $56 
Crude oil  13   4 
Total inventories $105  $60 
  December 31, 
  2009  2008 
(millions)      
Materials and Supplies $71  $92 
Crude Oil  18   13 
Total $89  $105 
 
Basic and Diluted Earnings Per Share—ShareBasic earnings per share (EPS) of our common stock have been computed on the basis of the weighted average number of shares outstanding during each period. The diluted EPS of  our common stock includes the effect of outstanding common stock equivalents. See Note 14 –14. Earnings Per Share.
 
Related Party Transactions—TransactionsWe Following the Patina Merger in 2005, we entered into a consulting agreement with a former officer of Patina who now serves as a member of our Board of Directors. Pursuant to the consulting agreement, the Board member served as a consultant to the combined company for a period of 12 months following the merger (May 16, 2005) in exchange for a monthly retainer of $50,000. In 2007, we reimbursed his office space rent of $42,000. In 2006, we paid consulting fees of $225,806 and reimbursed his office space rent of $72,000.$42,000 in 2007.
 
Contingencies—ContingenciesWe are subject to legal proceedings, claims and liabilities that arise in the ordinary course of business. We accrue for losses associated with legal claims when such losses are considered probable and the amounts can be reasonably estimated. See Note 17 –17. Commitments and Contingencies.
 
We self-insure the medical and dental coverage provided to certain employees, certain workers’ compensation and the first $1 million of general liability coverage. Liabilities are accrued for self-insured claims, or when estimated losses exceed coverage limits, and when sufficient information is available to reasonably estimate the amount of the loss.
 
Concentration of Market Risk—RiskDuring In 2009, Glencore Energy UK Ltd was the largest single non-affiliated purchaser of production and accounted for 25% of crude oil sales, or 16% of total oil, gas and NGL sales. In 2008, Suncor Energy Marketing was the largest single non-affiliated purchaser of production and accounted for 22% of crude oil sales, or 13% of total oil, gas and NGL sales. In 2007, Marathon Petroleum Supply Company was the largest single non-affiliated purchaser of production and accounted for 18% of crude oil sales, or 10% of total oil, gas and NGL sales. During 2006, Trafigura Beheer B.V. was the largest single non-affiliated purchaser of production and accounted for 28% of crude oil sales, or 15% of total oil, gas and NGL sales. Shell Trading (US) Company accounted for 18% of 2006 crude oil sales or 10% of 2006 total oil, gas and NGL sales. We believe the loss of any one purchaser would not have a material effect on our financial position or results of operationoperations since there are numerous potential purchasers of our production.

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Concentration of Credit Risk—RiskCertain of our financial instruments, including cash equivalents, trade and joint interest receivables and derivative instruments, may expose us to credit risk.  Substantially all of our cash at December 31, 20082009 is located in our foreign subsidiaries. The cash is denominated in US dollars and invested in highly liquid investment-grade securities, US Treasury securitiesmoney market funds and short term deposits with original maturities of three months or less at the time of purchase. Although our cash and cash equivalents are deposited with major international banks and financial institutions, concentrations of cash in certain foreign locations may increase credit risk. We monitor the creditworthiness of the banks and financial institutions with which we invest and review the securities underlying our investment accounts. We believe that losses from nonperformance are unlikely to occur; however, we are not able to predict sudden changes in creditworthiness.
 
Our accounts receivable result primarily from sales of crude oil, natural gas and NGL production production and electricity, and joint interest billings to our partners. The receivables reflect a broad national and international customer base, which limits our exposure to concentrations of credit risk.  The majority of these receivables have payment terms of 30 days or less.

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We continually monitor the creditworthiness of the counterparties, some of which are not as creditworthy as we are and may experience liquidity problems.  We have obtained credit enhancements from some parties in the way of parental guarantees or letters of credit, including from our largest international crude oil purchaser. However, we do not have all of our trade credit enhancedprotected through guarantees or credit support. Nonperformance by a trade creditor could result in losses. In third quarter 2008, we reduced the carrying value of a receivable from SemCrude L.P., a crude oil purchaser, and recognized a pre-tax charge of $38 million for a probable loss. We recorded an additional reduction in the carrying value of the SemCrude receivable, and corresponding pre-tax charge, of $12 million in 2009. See Note 17 –17. Commitments and Contingencies. See also allowance for Doubtful Accounts, above, for a discussion of accounts receivable from sales of electricity.
 
We use crude oil and natural gas derivative instruments to mitigate the effects of commodity price fluctuations and these derivative instruments expose us to counterparty credit risk. Our counterparties are major banks or financial institutions. Our derivative instruments are executed under master agreements which allow us, in the event of default, to elect early termination of all contracts with the defaulting counterparty. If we choose to elect early termination, all asset and liability positions with the defaulting counterparty would be net settled at the time of election.
We monitor the creditworthiness of our counterparties. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices as well as incur a loss. See Note 6 –6. Derivative Instruments and Hedging Activities – Receivables/Payables Related to Commodity Derivative Instruments.Activities.
 
Treasury Stock—We record treasury stock purchases at cost, which includes incremental direct transaction costs. Amounts are recorded as reductions in shareholders’ equity.
 
Foreign Currency—CurrencyThe US dollar is considered the functional currency for each of our international operations. Transactions that are completed in foreign currencies are remeasured into US dollars and recorded in the financial statements at prevailing foreign exchange rates. Transaction gains or losses were not material in any of the periods presented and are included in other non-operating (income) expense, net onin the consolidated statements of operations.
 
AdoptionRecently Adopted Standards The following standards have been adopted:
Recent SEC Rule-Making Activity   In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. The most significant amendments to the requirements included the following:

·Commodity Prices – Economic producibility of reserves and discounted cash flows is now based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
·Disclosure of Unproved Reserves – Probable and possible reserves may be disclosed separately on a voluntary basis.
·
Proved Undeveloped Reserves Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered and they are scheduled to be drilled within the next five years.
·Reserves Estimation Using New Technologies – Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
·Reserves Personnel and Estimation Process – Additional disclosure is required regarding the qualifications of the chief technical person who oversees the reserves estimation process.  We are also required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.

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·Disclosure by Geographic Area – Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.
·
Non-Traditional Resources – The definition of oil and gas producing activities has expanded and focuses on the marketable product rather than the method of extraction.
We adopted SFAS No. 123(R)the rules effective December 31, 2009. See Supplemental Oil and Gas Information (Unaudited) for impact of adoption on oil and gas reserves.
In addition, in January 2010, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (Update) 2010-03, "Oil and Gas Reserve Estimation and Disclosures", “Share-Based Payment” (SFAS 123(R))to provide consistency with the new SEC rules. The Update amends existing standards to align the reserves calculation and disclosure requirements under US GAAP with the requirements in the SEC rules. We adopted the new standards effective December 31, 2009. The new standards are applied prospectively as a change in estimate.  See also Supplemental Oil and Gas Information (Unaudited).
Postretirement Benefit Plan Asset Disclosures  In December 2008, the FASB issued new standards which require employers to make additional disclosures about plan assets for defined benefit pension and other postretirement benefit plans beginning with annual periods ending after December 15, 2009. Disclosures must provide an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period, and significant concentrations of risk within plan assets. We adopted the new standards as of December 31, 2009. Adoption of the new standards had no impact on our financial position or results of operations.  See Note 12. Benefit Plans.
Business Combinations and Noncontrolling Interests in Consolidated Financial Statements   In 2007, the FASB issued new standards regarding the accounting for business combinations and noncontrolling interests in consolidated financial statements. These standards require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. We adopted the new standards as of January 1, 2006. SFAS 123(R) revised SFAS No. 123, “Accounting for Stock-Based Compensation” and nullified APB 25 and its related implementation guidance. SFAS 123(R) requires companies to measure the grant-date fair value of stock options and other stock-based compensation issued to employees and expense the fair value over the requisite service period2009. There were no non-controlling interests at adoption date. Adoption of the award. SFAS 123(R) became effective for interimnew standards had no impact on our financial position or annual periods beginning January 1, 2006. See Note 13—Stock-Based Compensation.results of operations.
 
Adoption of SFAS 157Fair Value Measurements   – We adopted SFAS No. 157, “Fair Value Measurements” (SFAS 157), as of January 1, 2008 as related to our financial assets and liabilities. SFAS 157 establishesThe FASB’s fair value measurement standards establish a single authoritative definition of fair value based upon the assumptions market participants would use when pricing an asset or liability and createscreate a fair value hierarchy that prioritizes the information used to develop those assumptions. Under the standard,The standards require additional disclosures, are required, including disclosures of fair value measurements by level within the fair value hierarchy. As a result of adoption,January 1, 2008, we began incorporating a credit risk assumption intoadopted the measurement of certainnew standards as they related to our financial assets and liabilities. Adoption of SFAS 157 did not have a significant impact on our consolidated financial statements. See Note 5 – Fair Value Measurements.
As of January 1, 2009, we adopted SFAS 157the new standards as it relatesthey related to our nonfinancial assets and liabilities, including nonfinancial assets and liabilities measured at fair value in a business combination; impaired property, plant and equipment; goodwill;goodwill impairment; and initial recognition of asset retirement obligations. Adoption of SFAS 157 for our existing nonfinancial assets and liabilitiesthe new standards did not have a significant impact on our consolidated financial statements.
In April 2009, the FASB issued additional guidance clarifying the application of US GAAP for fair value measurements in the current economic environment, modifying the recognition of other-than-temporary impairments of debt securities, and requiring companies to disclose the fair value of financial instruments in interim periods. The revised guidance was effective for interim and annual periods ending after June 15, 2009. The guidance:
·describes how to determine the fair value of assets and liabilities in the current economic environment and reemphasizes that the objective of a fair value measurement remains the price that would be received to sell an asset or paid to transfer a liability at the measurement date;
·
modifies the requirements for recognizing other-than-temporarily impaired debt securities and significantly changes the existing impairment model for such securities. It also modifies the presentation of other-than-temporary impairment losses and increases the frequency of and expands already required disclosures about other-than-temporary impairment for debt and equity securities; and
·requires disclosures of the fair value of financial instruments in interim financial statements, the method or methods and significant assumptions used to estimate the fair value of financial instruments, and a discussion of changes, if any, in the method or methods and significant assumptions during the period.
We adopted this new guidance for the quarter ended June 30, 2009. Adoption of the new guidance had no impact on our financial position or results of operations.
 
InAdoption of SFAS 158—We adopted SFAS No. 158, “Employers’ August 2009, the FASB issued Accounting for Defined Benefit Pension and Other Postretirement Plans, an amendment of FASB Statements No. 87, 88, 106, and 132(R)” (SFAS 158) as of December 31, 2006. SFAS 158 requires plan sponsors of defined benefit pension and other postretirement benefit plansStandards Update 2009-5, “Measuring Liabilities at Fair Value” in order to recognize the funded status of their postretirement benefit plans in the statement of financial position,provide further guidance on how to measure the fair value of plan assets and benefit obligationsa liability. The Update clarifies that, in circumstances in which a quoted price in an active market for the identical liability is not available, a reporting entity is required to measure fair value using one or more prescribed techniques. We adopted the new guidance as of the dateOctober 1, 2009. Adoption of the fiscal year-end statement of financial position, and provide additional disclosures. The effect of adoptionnew guidance had no impact on our financial position or results of operations.
See Note 5. Fair Value Measurements and Disclosures.

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Fair Value Option  Under US GAAP for fair value measurements, companies have an option to report selected financial assets and liabilities at December 31, 2006 was included in our consolidated balance sheets.fair value. We adopted the new guidance for optional fair value measurements as of January 1, 2008. Adoption of SFAS 158the new guidance had no effect on our financial position or results of operations for the year ended December 31, 2006. See Note 12—Benefit Plans.as we made no elections to report selected financial assets or liabilities at fair value.
 
AdoptionDerivative Instruments and Hedging Activities   In March 2008, the FASB issued new standards which amended and expanded previous disclosure requirements related to derivative instruments and hedging activities. The new standards require qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of FSP FIN 39-1 –derivative instruments and related gains and losses, and disclosures about credit risk-related contingent features in derivative agreements. We adopted FASB Staff Position FIN 39-1, “An Amendment of FASB Interpretation No. 39” (FSP FIN 39-1),the new standards as of January 1, 2008. FSP FIN 39-1 addresses certain modifications2009. They provide only for enhanced disclosures, and adoption of the new standards had no impact on our financial position or results of operations. See Note 6. Derivative Instruments and Hedging Activities.
Subsequent Events  In May 2009, the FASB issued new standards which establish the accounting for and disclosure of events that occur after the balance sheet date but before financial statements are issued. In particular, the new standards set forth:
·the period after the balance sheet date during which management of a reporting entity should evaluate events or transactions that may occur for potential recognition or disclosure in the financial statements (through the date that the financial statements are issued or are available to be issued);
·the circumstances under which an entity should recognize events or transactions occurring after the balance sheet date in its financial statements; and
·the disclosures that an entity should make about events or transactions that occurred after the balance sheet date.
We adopted the new standards as of June 30, 2009. We have evaluated subsequent events after the balance sheet date of December 31, 2009 through the time of filing with the SEC on February 18, 2010, which is the date the financial statements were issued. See Note 4. Acquisitions and Divestitures – Pending Asset Acquisition and Note 6. Derivative Instruments and Hedging Activities – Interest Rate Hedges.
Accounting Standards Codification  In June 2009, the FASB established the FASB Accounting Standards Codification (Codification), which officially commenced July 1, 2009, to FIN 39, “Offsettingbecome the source of authoritative US GAAP recognized by the FASB to be applied by nongovernmental entities.  Rules and interpretive releases of the SEC under authority of federal securities laws are also sources of authoritative US GAAP for SEC registrants.  Generally, the Codification is not expected to change US GAAP.  All other accounting literature excluded from the Codification will be considered nonauthoritative.  The Codification is effective for financial statements issued for interim and annual periods ending after September 15, 2009.  We adopted the new standards for our quarter ending September 30, 2009.  All references to authoritative accounting literature are now referenced in accordance with the Codification.
Equity Method Investments  In November 2008, the FASB issued new guidance in accounting for equity method investments. The new guidance was issued to address questions that arose regarding the application of the equity method subsequent to the issuance of new business combination standards. The new guidance concluded that equity method investments should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, it clarified that an impairment assessment should be applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. We adopted the new guidance as of January 1, 2009. Adoption of the new guidance had no impact on our financial position or results of operations.
Offsetting of Amounts Related to Certain Contracts.” FSP FIN 39-1 allowsContracts    As of January 1, 2008 we adopted guidance allowing companies to offset fair value amounts recognized for derivative instruments and the fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral. The cash collateral (commonly referred to as a “margin”) must arise from derivative instruments recognized at fair value that are executed with the same counterparty under a master netting arrangement. Upon adoption of the new guidance, we elected to offset the right to reclaim cash collateral or the obligation to return cash collateral against our net derivative positions for which master netting agreements exist. As of December 31, 20082009 and 2007,2008, we had no significant cash collateral obligations.

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Adoption of FIN 48 – We adopted FASB Interpretation No. 48, “AccountingAccounting for Uncertainty in Income Taxes an interpretation of FASB Statement No. 109” (FIN 48) as   As of January 1, 2007. FIN 48 clarifies2007, we adopted new standards which clarified the accounting for uncertainty in income taxes recognized in a company’s financial statements in accordance with SFAS No. 109, “Accounting for Income Taxes”. FIN 48 prescribesstatements. The new standards prescribed a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48They also providesprovided guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We also adopted FASB Staff Position No. FIN 48-1, “Definition of Settlement in FASB Interpretation No. 48” (FSP FIN 48-1)Also as of January 1, 2007. FSP FIN 48-1 provides2007, we adopted related guidance regarding the definition of “settlement”. This guidance provided that a company’s tax position will be considered settled if the taxing authority has completed its examination, the company does not plan to appeal, and it is remote that the taxing authority would reexamine the tax position in the future. The adoptionAdoption of FIN 48 and FSP FIN 48-1the new guidance had no effect on our financial position or results of operations. See Note 9—9. Income Taxes.
 

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Note 3 –3.  Asset Impairments
 
2009 Asset Impairments    Pre-tax (non-cash) impairments for 2009 totaled $604 million and related to the following proved oil and gas properties and investments:
·$389 million related to Granite Wash, an onshore US development;
·$48 million related to Main Pass, our remaining operated Gulf of Mexico shelf asset;
·$44 million related to Paxton, an onshore US development;
·$23 million related to Raton, a deepwater Gulf of Mexico development; and
·$100 million related to our investment in Ecuador.
US Oil and Gas AssetsAs a result of a significant decline in the depressed economic environment, coupled with a severe decrease in commodity prices during the fourth quarter of 2008,forward natural gas price curve at March 31, 2009, we assessed the recoverability ofreviewed our oil and gas properties that are sensitive to natural gas price decreases for impairment. We determined that the carrying amount of Granite Wash, an onshore US area where we have significantly reduced investments beginning in 2007, was not recoverable from future cash flows and, other investmentstherefore, was impaired at March 31, 2009.  We reduced Granite Wash to its fair value, using a discounted cash flow method, as comparable market data was not available.  We also impaired our Main Pass asset in the Gulf of Mexico, which had been reclassified from held-for-sale to held-and-used.
At December 31, 2008. As a result of this analysis2009, we reviewed our significant properties for impairment and recorded impairment charges on two additional properties.  We determined that certainPaxton, an onshore US development was impaired primarily due to decreases in the forward natural gas price curve.  We also impaired Raton, a deepwater Gulf of our assets were impaired.  In addition, during third quarter 2008, we recorded an impairment charge relatedMexico development primarily due to an asset held for sale.  Total pre-tax (non-cash) impairments for 2008 were $294 million.well performance issues.  We reduced these properties to their fair values, using a discounted cash flow method, as comparable market data was not available.
 
Total asset impairment charges assessed under FAS 144 for 2008 were $219 million, of which $149 million related to ourOur US proved properties and $70 million related to(including our investmentMain Pass asset) were tested for impairment in Ecuador. These2009 in accordance with US GAAP for impairment or disposal of long-lived assets. The assets were written down to their estimated fair values which were determined using discounted cash flow models. The discounted cash flow models included management’s estimates of future oil and gas production, commodity prices based on December 31, 2008forward commodity price strips,curves as of the date of the estimate, operating and development costs, as well as appropriate and discount rates.
Investment in Ecuador    As a result of the increasingly unsettled economic and political environment in Ecuador, we also reviewed our investment in Ecuador for impairment as of December 31, 2009. We are aware that the Government of Ecuador is taking steps to renegotiate contracts or, in some cases, remove international oil and gas companies from its borders.  In recent years, certain international companies have been subject to expropriation, forced to abandon their oil and gas assets, or bought out of their government contracts.  On August 24, 2009, Ecuador’s National Bureau of Hydrocarbons (DNH) rejected our third and most recent proposed plan of development for the Amistad field in Block 3, offshore Ecuador and noted that it was treating the plan of development as if it had not been received.  We appealed the decision of the DNH, and it dismissed our appeal on November 11, 2009.  On November 12, 2009, Empresa Estatal Petroleos Del Ecuador (Petroecuador) initiated the procedure of caducidad (or termination) by providing us with a notice that alleged 15 instances of non-compliance with the production sharing contract for Block 3 (PSC).  On November 24, 2009, we responded to Petroecuador noting that its allegations had previously been resolved in our favor or otherwise addressed.  Nevertheless, on December 31, 2009, Petroecuador requested that Ecuador’s Minister of Non-Renewable Natural Resources commence termination of the PSC on the basis of the foregoing allegations and because a plan of development had not been approved. On February 11, 2010, the Minister notified us of Petroecuador's request by delivering to us a copy of a letter of non-compliance dated December 31, 2009. The Minister provided us with 60 business days to respond to the allegations contained in the letter. We intend to vigorously act to protect our interests, and are evaluating appropriate action.
 
We also perform periodic assessments related todetermined that the carrying value of our individually significant unproved properties.  Weinvestment in Ecuador exceeded its fair value by $100 million and we recorded an impairment charge for this amount in fourth quarter 2009. At December 31, 2009, we estimated the fair value of $75our investment in Ecuador using a probability-weighted discounted cash flow model that considered the likelihood of possible outcomes of (1) the event of continued operation of the assets in contemplation of resolving the dispute and in accordance with the existing contract, (2) the event of a sale of our investment to a third party, and (3) the event of arbitration with varying degrees of award and collection. The use of alternative judgments and/or assumptions could have resulted in the recognition of an impairment charge that was significantly different.  Future estimates of fair value may change, which could result in additional impairment charges. Our investment in Ecuador had a net book value of approximately $72 million after the December 31, 2009 impairment.
See also Note 5. Fair Value Measurements.
2008 Asset Impairments   As a result of the depressed economic environment, coupled with a severe decrease in commodity prices during the fourth quarter of 2008, we assessed the recoverability of our proved and unproved oil and gas properties and other investments as of December 31, 2008. As a result, we determined that certain of our assets were impaired. In addition, during third quarter 2008, we recorded an impairment charge related to our Main Pass asset based on anticipated sales proceeds less costs to sell. Total pre-tax (non-cash) impairment charges for 2008 were $294 million, as follows:  

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·$111 million related to various US proved oil and gas properties;
·$70 million related to our investment in Ecuador;
·$75 million related to various US unproved properties; and
·$38 million related to the Main Pass asset held for sale.
The impairments of unproved US unproved properties. These impairmentsoil and gas properties in 2008 were primarily related to allocated fair values attributable to probable and possible reserves acquired in previous business combinations. We assessed these properties using discounted cash flow models based on management’s assumptions of future production, commodity prices, operating and development costs, as well as appropriateand discount rates. 
 
Our US proved properties and investment in Ecuador were tested for impairment in 2008 in accordance with US GAAP for impairment or disposal of long-lived assets. The assets were written down to their estimated fair values which were determined using discounted cash flow models. The discounted cash flow models included management’s estimates of future oil and gas production, commodity prices based on forward commodity price curves as of the date of the estimate, operating and development costs, and discount rates.
Note 4—4.  Acquisitions and Divestitures
 
Mid-continent Acquisition –   In July 2008, we acquired producing properties in western Oklahoma for $292 million in cash.million. The total purchase price has been preliminarilywas allocated to the proved and unproved properties acquired based on fair values at the acquisition date. Approximately $254 million was allocated to proved properties and $38 million to unproved properties.
 
Main Pass Asset – We have initiated a process to sell our remaining operated non-core Gulf of Mexico shelf asset. This asset, located at Main Pass, suffered significant hurricane damage in 2004 and 2005 and has undergone cleanup activities that were completed in the third quarter of 2007. During the first half of 2007, several factors contributed to an increase in our estimated cleanup costs for damage and included cost escalation due to weather delays and an increase in effort for the design and construction of the deck lifting barge and mooring system, as well as additional costs for the actual deck lifting activities.  These increases caused the total project costs, combined with net book value of the assets destroyed, to exceed certain insurance coverage limitations.  As a result, we recorded $51 million as a loss on involuntary conversion.
In 2008, in anticipation of the sale, we recorded an impairment loss of $38 million (based on anticipated proceeds less costs to sell) related to the Main Pass asset. We also recorded a loss on involuntary conversion of $9 million upon resolution of our insurance claims related to the hurricane damage sustained in 2005. An asset held for sale of $26 million is included in current assets and associated asset retirement obligations of $15 million are included in current liabilities in our consolidated balance sheets at December 31, 2008.
Through December 31, 2008, we received $330 million of insurance recoveries related to damage caused by Hurricanes Ivan and Katrina. As of December 31, 2008, we recorded probable insurance claims of $10 million. Insurance reimbursements received for cleanup and repair costs are included in cash flows from operating activities.
Sale of Argentina Assets—   In February 2008, effective July 1, 2007, we sold our interest in Argentina for a sales price of $117.5 million. The sale iswas subject to Argentine government approval, which has not been received.

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Accordingly, theapproval. The $24 million gain on sale of approximately $24 million has beenwas deferred in other current liabilities until approval is obtained. We are currently unable to predictsecond quarter 2009 when the Argentine government approval will be obtained.approved the sale.
 
Sale of Gulf of Mexico Shelf PropertiesMain Pass Asset —In 2006,2008, we completed the sale of essentially all ofinitiated a process to sell our remaining operated non-core Gulf of Mexico shelf properties except forasset located at Main Pass. Numerous parties expressed an interest in purchasing the asset. However, due to difficulties in obtaining appropriate insurance, bonding or financing, none of the potential buyers were able to close on the sale. As a result, the asset was reclassified from held-for-sale to held-and-used in first quarter 2009.  Due to significant increases in insurance costs and exposure to further windstorm damage, we are in the process of abandoning the Main Pass asset which required repairs related to hurricane damage at the time. Pretax cash proceeds from the sale totaled $506 million including proceeds received from parties who exercised preferential rights to purchase certain minor properties. We recorded a pretax gain of $211 million from the sale. The net book value of properties sold totaled $229 million. Asset retirement obligations of $45 million, related to the Gulf of Mexico shelf properties, were also included in the sale. In accordance with SFAS 142, we allocated $100 million of our US reporting unit goodwill to the sale. The property disposition did not qualify for accounting as discontinued operations, in accordance with EITF 03-13, “Applying the Conditions in Paragraph 42 of FASB Statement No. 144 in Determining Whether to Report Discontinued Operations”. This is due to the migration of our investment and operations to the deepwater Gulf of Mexico which we believe is an area of higher potential.
As a result of the sale, we recognized a pretax charge of $399 million related to cash flow hedge losses which were reclassified from AOCL to earnings. This reclassification reflected the mark-to-market value of the cash flow hedges that related to Gulf of Mexico shelf production. asset.  See Note 6—Derivative Instruments and Hedging Activities.3.  Asset Impairments.
 
PurchasePending Asset Acquisition     On December 31, 2009, we entered into a definitive agreement to acquire substantially all of U.S. Exploration Holdings,the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc.—In 2006, we purchased and Suncor Energy (Natural Gas) America Inc. for $494 million. The acquisition is expected to close late in the common stock of U.S. Exploration, a privately held corporation, for a cash purchase price of $412 million plus liabilities assumed. U.S. Exploration’s reservesfirst quarter 2010 and production are located in Colorado’s Wattenberg field. The total purchase price was allocatedis subject to the assets acquired and liabilities assumed based on fair values at the acquisition date as follows:customary closing conditions. Funding is expected to be provided through our existing credit facility.
 
·$413 million to proved oil and gas properties;
·$131 million to unproved oil and gas properties;
·$34 million to goodwill; and
·$172 million to deferred income taxes.
Note 5.  Fair Value Measurements and Disclosures
 
Note 5 –Assets and Liabilities Measured at Fair Values ofValue on a Recurring Basis   Financial Instruments
Certain of our assets and liabilities are reportedmeasured at fair value on a recurring basis in our consolidated balance sheets.  The following methods and assumptions were used to estimate the fair values for each class of financial instruments:values: 
 
Cash, Cash Equivalents, Accounts Receivable and Accounts Payable  –The carrying amounts approximate fair value due to the short-term nature or maturity of the instruments.
 
Mutual Fund Investments  –Our mutual fund investments, which primarily include assets held in a rabbi trust, consist of various publicly-traded mutual funds that include investments ranging from equities to money market instruments. The fair values are based on quoted market prices.prices for identical assets.
 
Commodity Derivative Instruments –   Our commodity derivative instruments consist of variable to fixed price commodity swaps, costless collars and basis swaps. We estimate the fair values of these instruments based on published forward commodity price curves for the underlying commodities as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published LIBOR rates, Eurodollar futures rates and interest swap rates. The fair values alsoof commodity derivative instruments in an asset position include a measure of counterparty creditnonperformance risk, orand the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published credit default swap rates. In addition, for costless collars, we estimate the option value of the contract floors and ceilings using an option pricing model which takes into account market volatility, market prices and contract parameters. terms. See Note 6 –6. Derivative Instruments and Hedging Activities.
 








Patina Deferred Compensation Liability   The value is dependant upon the fair values of mutual fund investments and shares of our common stock held in a rabbi trust. See Mutual Fund Investments above.
 

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Noble Energy, Inc.
Notes to Consolidated Financial Statements


Fair valueMeasurement information for financial assets and liabilities that are measured at fair value each reporting period ison a recurring basis was as follows at December 31, 2008:follows:
 
   Fair Value Measurements Using       
   Quoted Prices  Significant Other Significant      
    in Active   Observable  Unobservable     Fair 
    Markets   Inputs  Inputs  Netting  Value 
   (Level 1)  (Level 2) (Level 3) 
  Adjustment (1)
 Measurement 
   (in millions) 
Financial assets                
Mutual fund investments $      84 $         - $- $         - $          84 
Commodity derivative instruments         -           492          -         (22)             470 
Financial liabilities                
Commodity derivative instruments         -            (47)          -           22              (25) 
   Fair Value Measurements Using         
   
Quoted Prices in Active Markets
(Level 1)
 Significant Other Observable Inputs (Level 2)  Significant Unobservable Inputs (Level 3)  
Adjustment (1)
  Fair Value Measurement 
(millions)                    
December 31, 2009                    
Financial Assets                    
Mutual Fund Investments $   108  $-  $-  $-  $  108 
Commodity Derivative Instruments            -          42   -         (28)         14 
Financial Liabilities                    
Commodity Derivative Instruments            -      (145)   -          28       (117) 
Patina Deferred Compensation Liability      (168)           -    -             -       (168) 
December 31, 2008                    
Financial Assets                    
Mutual Fund Investments $   84  $-  $ -  $-  $ 84 
Commodity Derivative Instruments            -        492    -         (22)        470 
Financial Liabilities                    
Commodity Derivative Instruments            -        (47)   -          22         (25) 
Patina Deferred Compensation Liability      (123)           -   -             -       (123) 
 
(1)Amount represents the impact of master netting agreements that allow us to settle asset and liability positions with the same counterparty.

SFAS 157, which we adopted asAssets and Liabilities Measured at Fair Value on a Nonrecurring Basis   Certain assets and liabilities are measured at fair value on a nonrecurring basis in our consolidated balance sheets. As of January 1, 2008, establishes a2009, we adopted US GAAP fair value hierarchy which prioritizes the inputsmeasurement standards as they related to valuation techniquesour nonfinancial assets and liabilities.
The following methods and assumptions were used to measureestimate the fair values for nonrecurring measurements made in 2009: 
Proved Property Impairments  In accordance with US GAAP for the impairment or disposal of long-lived assets, we review a proved oil and gas property for impairment when events and circumstances indicate a possible decline in the recoverability of the carrying value of such property. We estimate the future cash flows expected in connection with the property and compare such future cash flows to the carrying amount of the property to determine if the carrying amount is recoverable. If the carrying amount of the property exceeds its estimated undiscounted future cash flows, the carrying amount of the property is reduced to its estimated fair value. Fair value may be estimated using comparable market data, a discounted cash flow method, or a combination of the two. In the discounted cash flow method, estimated future cash flows are based on management’s expectations for the future and include estimates of future oil and gas production, commodity prices based on published forward commodity price curves as of the date of the estimate, operating and development costs, and a risk-adjusted discount rate.
Measurement information for proved properties measured at fair value into three levels. The fair value hierarchy gives the highest priorityon a nonrecurring basis in 2009 was as follows:
       Fair Value Measurements Using    
Description  
Fair Value
Measurement (1)
  
Quoted Prices in
Active Markets
(Level 1)
  
Significant Other
Observable Inputs
(Level 2)
  
Unobservable
Inputs
(Level 3)
  
Total
Impairment
Loss
 
(millions)                  
Year Ended December 31, 2009                  
Impaired US Oil and Gas Properties $      363  $            - $          -  $363 $  504 
Impaired Investment in Ecuador              72               -           -           72            100 
(1)
Amount represents the fair values of the impaired properties as of the dates of the assessments, March 31, 2009 and December 31, 2009. See Note 3. Asset Impairments.

84
Noble Energy, Inc.
Notes to quoted market prices (unadjusted) in active markets for identical assets or liabilities (Level 1) and the lowest priority to unobservable inputs (Level 3). Level 2 inputs are inputs, other than quoted prices included within Level 1, which are observable for the asset or liability, either directly or indirectly. We use Level 1 inputs when available as Level 1 inputs generally provide the most reliable evidence of fair value.Consolidated Financial Statements


Additional Fair Value Disclosures
 
Debt   –The fair value of fixed-rate debt is estimated based on the published market prices for the same or similar issues.  The fair value of floating-rate debt is estimated using the carrying amounts because the interest rates paid on such debt are set for periods of three months or less. See Note 8—8. Debt.
 
AdditionalFair value information regarding our debt is as follows:
 
  December 31,
  2008  2007
  Carrying  Fair  Carrying  Fair
  Amount  Value  Amount  Value
  (in millions)
Total debt, net of unamortized discount$      2,266  $   2,172 $     1,876 $     1,920
  December 31, 
  2009  2008 
  Carrying Amount  Fair Value  Carrying Amount  Fair Value 
(millions)            
Long-Term Debt, Net of Unamortized Discount (1)
 $2,008  $2,279  $2,266  $2,172 
 
(1)Excludes obligation under FPSO lease.

Note 6—6.  Derivative Instruments and Hedging Activities
 
CommodityObjective and Strategies for Using Derivative Instruments—We use various derivative instruments in connection with anticipated   In order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our crude oil and natural gas, saleswe enter into crude oil and natural gas price hedging arrangements with respect to minimize the impacta portion of commodity price fluctuations on cash flows. Suchour expected production. The derivative instruments we use include variable to fixed price commodity swaps, costless collars and basis swaps. While these instruments mitigate the cash flow risk of future reductions in commodity prices they may also curtail benefits from future increases in commodity prices. We account for derivative instruments and hedging activities in accordance with SFAS 133US GAAP for derivative instruments and hedging activities, and all derivative instruments are reflected at fair value onin our consolidated balance sheets. We elected to designate the majority of our commodity derivative instruments as cash flow hedges through December 31, 2007. As discussed in Note 2—2. Summary of Significant Accounting Policies – Derivative Instruments and Hedging Activities, we voluntarily discontinued cash flow hedge accounting for our commodity derivative instruments effective January 1, 2008. See Note 5 –5. Fair Values of Financial InstrumentsValue Measurements and Disclosures for a discussion of methods and assumptions used to estimate the fair values of our commodity derivative instruments. See Note 2. Summary of Significant Accounting Policies – Concentration of Credit Risk for a discussion of counterparty credit risk.
 

74
Table of ContentsAccounting for Commodity Derivative Instruments

The components of (gain) loss on  During 2009 and 2008, we accounted for our commodity derivative instruments includedusing mark-to-market accounting, and we recognized all gains and losses on such instruments in earnings during the consolidated statementsperiod in which they occur.  Prior to January 1, 2008, we elected to designate certain of operations include the following:
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Unrealized gain on commodity derivative instruments $(522) $-  $- 
Realized (gain) loss on commodity derivative instruments  82   -   (41)
Reclassified from AOCL (1)
  -   -   424 
Ineffectiveness (gain) loss  -   (2)  9 
(Gain) loss on commodity derivative instruments $(440) $(2) $392 
(1)Under our previous cash flow hedge accounting, if it became probable that the hedging instrument was no longer highly effective, the hedging instrument lost hedge accounting treatment. All current mark-to-market gains and losses were recordedour commodity derivative instruments as cash flow hedges. Net derivative gains and losses that were deferred in earnings and all accumulated gains or losses recorded in AOCL related to the hedging instrument were also reclassified to earnings. During 2006, we reclassified a pretax charge of $399 million from AOCL to earnings when it became probable that forecasted crude oil and natural gas sales would not occur due to the sale of Gulf of Mexico shelf properties. A mark-to-market gain of $39 million and the reclassification of a pretax charge of $25 million from AOCL to earnings due to the impacts of Hurricanes Katrina and Rita on the timing of forecasted Gulf of Mexico production were also included in 2006.
Crude oil and natural gas sales include amounts reclassified from AOCL as follows:of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur.  See Derivative Instruments in Previously Designated Cash Flow Hedging Relationships table below.

  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
(Decrease) in crude oil sales $(365) $(223) $(191)
Increase (decrease) in natural gas sales  34   169   (41)
Total (decrease) in crude oil and natural gas sales $(331) $(54) $(232)
Unsettled Derivative InstrumentsAs of December 31, 2008 and 2007, the balance in AOCL included net deferred losses of $48 million and $255 million, respectively, related to the fair value of crude oil and natural gas derivative instruments accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $29 million and $153 million, respectively. Approximately $36 million of deferred losses (net of tax) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at December 31, 2008 will be reclassified to earnings during the next 12 months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $57 million before tax. All forecasted transactions currently being hedged are expected to occur by December 2010.
As of December 31, 2008,2009, we had entered into the following crude oil derivative instruments:
 
  Variable to Fixed Price Swaps Costless Collars 
       Weighted      Weighted Weighted 
Production   Bbls  Average   Bbls  Average Average 
Period Index Per Day  Fixed Price Index Per Day  Floor Price Ceiling Price 
2009 NYMEX WTI         9,000 $        88.43 NYMEX WTI        6,700 $    79.70 $90.60 
2009 Dated Brent         2,000           87.98 Dated Brent        5,074       70.62       87.93 
2009 Average         11,000           88.35        11,774       75.79       89.45 
                   
2010        NYMEX WTI        5,500       69.00       85.65 
  Variable to Fixed Price Swaps Collars 
Production Period Index Bbls Per Day  Weighted Average Fixed Price Index Bbls Per Day  Weighted Average Floor Price  Weighted Average Ceiling Price 
                   
2010 NYMEX WTI  1,000  $78.70 NYMEX WTI  14,500  $61.48  $75.63 
2010 Dated Brent  1,000   80.05 Dated Brent  7,000   64.00   73.96 
2010 Average    2,000   79.38    21,500   62.30   75.09 
                        
2011  -  -   - NYMEX WTI  6,000   79.00   87.42 
 
From January 1, 20092010 to February 18, 2009,5, 2010, we entered into additional NYMEX WTI costlessswaps covering 2,000 Bbls per day for April through December 2010 with a weighted average fixed price of $85.69.  We also entered into additional NYMEX WTI collars covering 2,000 Bbls per day for calendar year 2010.

2011 with weighted average floor and ceiling prices of $84.00 and $92.70, respectively.
 

7585
Noble Energy, Inc.
Notes to Consolidated Financial Statements



As of December 31, 2008,2009, we had entered into the following natural gas derivative instruments:
 
  Costless Collars 
       Weighted Weighted 
Production   MMBtu  Average Average 
Period Index Per Day  Floor Price Ceiling Price 
2009 NYMEX HH    170,000 $     9.15 $10.81 
2009 
IFERC CIG (1)
      15,000         6.00         9.90 
2009 Average      185,000         8.90       10.73 
            
2010  IFERC CIG      15,000         6.25         8.10 
  Variable to Fixed Price Swaps Collars 
Production Period Index  MMBtu Per Day  Weighted Average Fixed Price Index MMBtu Per Day  Weighted Average Floor Price  Weighted Average Ceiling Price 
2010 NYMEX HH   20,000  $6.10 
NYMEX HH (1)
  210,000  $5.90  $6.73 
2010  -   -   - 
IFERC CIG (2)
  15,000   6.25   8.10 
2010 Average      20,000   6.10    225,000   5.93   6.82 
2011  -   -   -  NYMEX HH  140,000   5.95   6.82 
 
(1)Henry Hub
(2)Colorado Interstate Gas – Northern System
 
From January 1, 2010 to February 5, 2010, we entered into additional NYMEX HH swaps covering 20,000 MMBtu per day for April through December 2010, and 25,000 MMBtu per day for calendar year 2011 with weighted average fixed prices of $6.11 and $6.41, respectively.
As of December 31, 2008,2009, we had entered into the following natural gas basis swaps:
 
  Basis Swaps 
         Weighted 
Production   Index Less MMBtu  Average 
Period Index Differential Per Day  Differential 
2009 IFERC CIG  NYMEX HH  140,000  $2.49 
2010 IFERC CIG  NYMEX HH  20,000   1.99 
  Basis Swaps 
Production Period Index Index Less Differential MMBtu Per Day Weighted Average Differential
2010 IFERC CIG  NYMEX HH      100,000��$(1.60) 
2011 IFERC CIG  NYMEX HH      110,000        (0.76) 
 
From January 1, 20092010 to February 18, 2009,5, 2010, we entered into an additional IFERC CIG basis swapsswap covering 30,00010,000 MMBtu per day for calendar year 2010.April through December 2010 with a NYMEX HH to IFERC CIG differential of $(0.44).
 
The costless collar, fixed price swap and basis swap contracts entitle us (floating price payor) to receive settlement from the counterparty (fixed price payor) for each calculation period in amounts, if any, by which the settlement price for the scheduled trading days applicable for each calculation period is less than the fixed price or floor price. We would pay the counterparty if the settlement price for the scheduled trading days applicable for each calculation period is more than the fixed price or ceiling price. The amount payable by us, if the floating price is above the fixed or ceiling price, is the product of the notional quantity per calculation period and the excess, if any, of the floating price over the fixed or ceiling price in respect of each calculation period. The amount payable by the counterparty, if the floating price is below the fixed or floor price, is the product of the notional quantity per calculation period and the excess, if any, of the fixed or floor price over the floating price in respect of each calculation period.
 
OtherFair Value Amounts and Gains and Losses on Derivative Instruments—In addition to the derivative instruments described above, we may employ derivative instruments in connection with purchases and sales of production in order to establish a fixed margin and mitigate the risk of price volatility. Most of the purchases are on an index basis. However, purchasers in the markets in which we sell often require fixed or NYMEX-related pricing. We may use a derivative instrument to convert the fixed or NYMEX sale to an index basis thereby determining the margin and minimizing the risk of price volatility.
Receivables/Payables Related to Commodity Derivative Instruments—The fair values of derivative instruments included in theour consolidated balance sheets arewere as follows:
 
Commodity Derivative Instruments Not Designated as Hedging Instruments 
Asset Derivative Instruments Liability Derivative Instruments 
December 31, December 31, 
2009 2008 2009 2008 
Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value Balance Sheet Location Fair Value 
(millions)       (millions)       
Current Assets $13 Current Assets $437 Current Liabilities $100 Current Liabilities $23 
Noncurrent Assets  1 Noncurrent Assets  33 Noncurrent Liabilities  17 Noncurrent Liabilities  2 
 Total $14 Total $470 Total $117  Total $25 


86
Noble Energy, Inc.
Notes to Consolidated Financial Statements

  December 31, 
  2008  2007 
  (in millions) 
Commodity derivative instruments      
Current asset $437  $15 
Long-term asset  33   5 
Current liability  (23)  (540)
Long-term liability  (2)  (83)

The effect of derivative instruments on our consolidated statements of operations was as follows:
Commodity Derivative Instruments Not Designated as Hedging Instruments 
Amount of (Gain) Loss on Derivative Instruments Recognized in Income 
   Year Ended December 31, 
   2009  2008  2007 
(millions)          
Realized Mark-to-Market (Gain) Loss $(496) $   82 $          - 
Unrealized Mark-to-Market (Gain) Loss           606         (522)             - 
Ineffectiveness (Gain) Loss               -                -           (2) 
Total (Gain) Loss on Commodity Derivative Instruments $110 $(440) $  (2) 
Derivative Instruments in Previously Designated Cash Flow Hedging Relationships 
  Amount of (Gain) Loss on Derivative Instruments Recognized in Other Comprehensive (Income) Loss  Amount of (Gain) Loss on Derivative Instruments Reclassified from Accumulated Other Comprehensive Loss 
  2009  2008  2007  2009  2008  2007 
(millions)                  
Commodity Derivative Instruments (1)
                  
Crude Oil (2)
 $-  $-  $343  $58  $365  $223 
Natural Gas (2)
  -   -   (48)  -   (34)  (169)
Treasury Rate Locks  -   (1)  1   1   1   1 
Total $-  $(1) $296  $59  $332  $55 

(1)Includes effect of commodity derivative instruments previously accounted for as cash flow hedges. Net derivative gains and losses that were deferred in AOCL as of January 1, 2008, as a result of previous cash flow hedge accounting, are reclassified to earnings in future periods as the original hedged transactions occur.
(2)The amount of (gain) loss on derivative instruments reclassified from AOCL is recognized in oil, gas and NGL sales within our consolidated statements of operations.
AOCL   As of December 31, 2009 and 2008, the balance in AOCL included net deferred losses of $12 million and $48 million, respectively, related to the fair value of crude oil and natural gas derivative instruments accounted for as cash flow hedges. The net deferred losses are net of deferred income tax benefits of $7 million and $29 million, respectively. The net deferred losses (net of tax) related to the fair values of the commodity derivative instruments previously designated as cash flow hedges and remaining in AOCL at December 31, 2009 will be reclassified to earnings during the next 12 months as the forecasted transactions occur, and will be recorded as a reduction in oil and gas sales of approximately $20 million before tax. All forecasted commodity transactions currently being hedged are expected to occur by December 2010.
 
Interest Rate Lock—Hedges   We occasionally enter into forward contracts or swap agreements to hedge exposure to interest rate risk. Changes in fair value of interest rate swaps or interest rate “locks” used as cash flow hedges are reported in AOCL, to the extent the hedge is effective, until the forecasted transaction occurs, at which time they are recorded as adjustments to interest expense over the term of the related notes. At December 31, 20082009 and 2007,2008, AOCL included deferred losses, net of tax, of $3$2 million and $4$3 million, respectively, related to interest rate swaps. This amount is being reclassified into earnings, at the rate of $0.8 million per year, as an adjustment to interest expense over the term of our 5¼% senior notes due 2014.
 

76

As of December 31,In 2007, we had entered into two additional interest rate locks, each in the notional amount of $500 million. The locks were based on five and ten year US Treasury rates of 3.55% and 4.15%, respectively, and were scheduled to expire in September 2008. We settled the locks in July 2008 at a total cost of $0.2 million.
 
In January 2010, in anticipation of a long-term debt issuance, we entered into an interest rate forward starting swap to effectively fix the cash flows related to interest payments on the anticipated debt issuance. We are accounting for the instrument as a cash flow hedge against the variability of interest payments attributable to changes in interest rates on the forecasted issuance of fixed-rate debt. The swap is in the notional amount of $500 million and is based on a 30-year LIBOR swap rate.

Note 7—
87
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Note 7. Capitalized Exploratory Well Costs
 
We capitalize exploratory well costs until a determination is made that the well has found proved reserves or is deemed noncommercial, in which case the well costs are immediately charged to exploration expense.
 
Changes in capitalized exploratory well costs are as follows and exclude amounts that were capitalized and subsequently expensed in the same period:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
          
Capitalized exploratory well costs, beginning of period $249  $80  $35 
Additions to capitalized exploratory well costs pending determination of proved reserves
  253   182   63 
Reclassified to proved oil and gas properties based on determination of proved reserves
  -   (7)  (17)
Capitalized exploratory well costs charged to expense  (1)  (6)  (1)
Capitalized exploratory well costs, end of period $501  $249  $80 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Capitalized Exploratory Well Costs, Beginning of Period $501  $249  $80 
Additions to Capitalized Exploratory Well Costs Pending Determination of Proved Reserves  136   253   182 
Reclassified to Proved Oil and Gas Properties Based on Determination of Proved Reserves  (198)  -   (7)
Capitalized Exploratory Well Costs Charged to Expense  (7)  (1)  (6)
Capitalized Exploratory Well Costs, End of Period $432  $501  $249 
 
The following table provides an aging of capitalized exploratory well costs (suspended well costs) based on the date the drilling was completed and the number of projects for which exploratory well costs have been capitalized for a period greater than one year since the completion of drilling:
 
  December 31, 
  2008  2007  2006 
  (in millions) 
Exploratory well costs capitalized for a period of one year or less $256  $187  $58 
Exploratory well costs capitalized for a period greater than one year after completion of drilling
  245   62   22 
Balance, end of period $501  $249  $80 
             
Number of projects with exploratory well costs that have been capitalized for a period greater than one year after completion of drilling  6   5   4 
  December 31, 
  2009  2008  2007 
(millions)         
Exploratory Well Costs Capitalized for a Period of One Year or Less $158  $256  $187 
Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling  274   245   62 
Balance at End of Period $432  $501  $249 
Number of Projects with Exploratory Well Costs That Have Been Capitalized for a Period Greater Than One Year After Completion of Drilling  5   6   5 
 
The following table provides a further aging of those exploratory well costs that have been capitalized for a period greater than one year since the completion of drilling as of December 31, 2008:2009:
 
   Suspended Since 
  Total  2007  2006  2005 
  (in millions) 
Project            
West Africa $160  $140  $1  $19 
Raton South (deepwater Gulf of Mexico)  28   5   23   - 
Redrock (deepwater Gulf of Mexico)  17   -   17   - 
Flyndre (North Sea)  15   12   3   - 
Selkirk (North Sea)  22   22   -   - 
Other  3   -   3   - 
Total exploratory well costs capitalized for a period greater than one year after completion of drilling
 $245  $179  $47  $19 
     Suspended Since 
  Total  2008  2007  2006 & Prior 
(millions)            
Project            
Blocks O and I (West Africa) $172  $62  $96  $14 
Gunflint (Deepwater Gulf of Mexico)  49   49   -   - 
Redrock (Deepwater Gulf of Mexico)  17   -   -   17 
Flyndre (North Sea)  15   -   12   3 
Selkirk (North Sea)  21   -   21   - 
Total Exploratory Well Costs Capitalized for a Period Greater Than One Year After Completion of Drilling $274  $111  $129  $34 
 
Exploratory well costs capitalized for more than one year at December 31, 2008 include six projects, one of which includes activity in West Africa. We incurred exploratory well costs of $160 million inBlocks O and I (West Africa)  The West Africa forproject includes Blocks O and I offshore Equatorial Guinea and the PH-77 licenseYoYo mining concession and Tilapia production sharing contract offshore Cameroon. Since drilling the initial well for this project, additional seismic work has been completed and exploration and appraisal wells have been drilled to further evaluate our discoveries. The West Africa development team is proceeding with a program to further define the resources in this area such that an optimal development program may be designed. Accordingly, a development plan
On July 22, 2009, we announced that the Plan of Development for the Benita discoveryAseng field (formerly Benita) on Block I was submittedhas been sanctioned by us, our partners, and the Ministry of Mines, Industry, and Energy of the Republic of Equatorial Guinea.  As a result, we reclassified $76 million of capitalized costs relating to the Equatorial Guinean governmentAseng field out of capitalized exploratory well costs and into proved oil and gas properties.
We have evaluated the potential for additional liquids and gas projects, and expect that the next development will be at the Belinda field.  Belinda project sanction is currently scheduled to occur in December 2008,2010 with production beginning in 2013. We are also evaluating future oil projects at Diega and Carmen and are currently scheduling first production for 2014, subject to sanctioning. In Cameroon, we await their approval. will acquire a 3-D seismic survey over YoYo and portions of Tilapia during 2010, and exploration drilling is currently planned in Tilapia for 2011.

88
Noble Energy, Inc.
Notes to Consolidated Financial Statements


In addition to the amount ofremaining exploratory well costs that have been capitalized for a period greater than one year for the West Africa project, we have incurred $108$27 million in suspended costs related to additional drilling activity in West Africa through December 31, 2008.2009.
Gunflint (Deepwater Gulf of Mexico)   Gunflint (Mississippi Canyon Block 948) was a 2008 crude oil discovery and is our largest deepwater Gulf of Mexico discovery to date. We have acquired additional seismic information and are preparing to drill one or two appraisal wells in 2010.
 


Additionally, we incurred exploratory well costs related to two projects in the deepwaterRedrock (Deepwater Gulf of Mexico.  One project relates to Raton South (Mississippi Canyon Block 292) and includes $28 million of suspended exploratory well costs. A successful sidetrack well was recently completed on this prospect and tie-back to a host facility is anticipated in late 2009. The other project relates toMexico)   Redrock (Mississippi Canyon Block 204) was a 2006 natural gas/condensate discovery and includes $17 millionis currently considered a co-development candidate with South Raton (Mississippi Canyon Block 292). The anticipated development plan consists of suspended exploratory well costs.tying South Raton back through the Gemini system to a host platform at Viosca Knoll Block 900 for processing and then connecting Redrock into this gathering system. Tie-back of Redrock is anticipated to occur following the tie-backdevelopment of Raton South.South Raton.
 
Flyndre (North Sea) The Flyndre and Selkirk projects areproject is located in the UK sector of the North Sea and incurred exploratory well costs of $15 million and $22 million, respectively.  Wewe successfully completed an exploratory appraisal well at each project in 2007 and2007.  We are currently working with the co-venturersproject operator and other partners to formulatefinalize the field development plans.
The remaining project, which totals $3 million in suspended exploratory well costs, continues to be evaluated by various means including additional seismic work, drilling additional wellsplan and evaluating the potential of the exploration well.relevant operating agreements.
 
Selkirk (North Sea)   The Selkirk project is also located in the UK sector of the North Sea. Capitalized costs to date primarily consist of the cost of drilling an appraisal well which was then sidetracked to the original discovery well location, to ensure presence of effective reservoir, and suspended as a future producer. We are currently working with our partners on an alternative host and to reduce costs.
Note 88.  Long-Term Debt—Debt
 
Our debt consists of the following:
 
  December 31, 
  2008  2007 
  Debt Interest Rate  Debt Interest Rate 
  (in millions, except percentages) 
Credit facility $1,606  0.80% $1,180  5.28%
5 ¼% Senior Notes, due April 15, 2014  200  5.25%  200  5.25%
7 ¼% Notes, due October 15, 2023  100  7.25%  100  7.25%
8% Senior Notes, due April 1, 2027  250  8.00%  250  8.00%
7 ¼% Senior Debentures, due August 1, 2097  89  7.25%  100  7.25%
Installment payments, due May 11, 2009  -  -   25  5.53%
Long-term debt  2,245      1,855    
Installment payments - current portion  25  4.18%  25  5.53%
Total debt  2,270      1,880    
Unamortized discount  (4)     (4)   
Total debt, net of discount $2,266     $1,876    
  December 31, 
  2009  2008 
  Debt  Interest Rate  Debt  Interest Rate 
(millions, except percentages)            
Credit Facility (1)
 $382   0.54% $1,606   0.80%
5¼% Senior Notes, due April 15, 2014  200   5.25%  200   5.25%
8¼% Senior Notes, due March 1, 2019  1,000   8.25%  -   - 
7¼% Notes, due October 15, 2023  100   7.25%  100   7.25%
8% Senior Notes, due April 1, 2027  250   8.00%  250   8.00%
7¼% Senior Debentures, due August 1, 2097  84   7.25%  89   7.25%
Obligation Under FPSO Lease (2)
  29   -   -   - 
Long-term Debt  2,045       2,245     
Installment Payment, due May 11, 2009  -   -   25   4.18%
Total Debt  2,045       2,270     
Unamortized Discount  (8)      (4)    
Total Debt, Net of Discount $2,037      $2,266     
(1)We expect to use the credit facility to fund our planned $494 million acquisition of US Rocky Mountain assets in the first quarter 2010. See Note 4. Acquisitions and Divestitures – Pending Asset Acquisition.
(2)
Amount reported is based on percentage of FPSO construction activities completed as of December 31, 2009 and therefore does not reflect future minimum lease obligations. See Obligation Under FPSO Lease below.
 
All of our long-term debt is senior unsecured debt and is, therefore, pari passu with respect to the payment of both principal and interest. The indenture documents of each of the 7¼% Notes, the 8% Senior Notes and the 7¼% Senior Debenturesour notes provide that we may prepay the instruments by creating a defeasance trust. The defeasance provisions require that the trust be funded with securities sufficient, in the opinion of a nationally recognized accounting firm, to pay all scheduled principal and interest due under the respective agreements. Interest on each of these issues is payable semi-annually. Debt issuance costs of approximately $6$13 million (including $2 million related to the credit facility) remain and are being amortized to expense over the life of the related debt issue.issues.
 
Credit Facility—Facility   In November 2007, we extended ourOur bank revolving credit facility (the credit facility) until December 9, 2012.  The commitment is committed in the amount of $2.1 billion until December 9, 2011 at which time the commitment reduces to $1.8 billion. The credit facility (i) provides for credit facility fee rates that range from 5 basis points to 15 basis points per year depending upon our credit rating, (ii) makes available short-term loans up to an aggregate amount of $300 million and (iii) provides for interest rates that are based upon the Eurodollar rate plus a margin that ranges from 20 basis points to 70 basis points depending upon our credit rating and utilization of the credit facility. The credit facility requires that our total debt to capitalization ratio (as defined in the credit agreement), expressed as a percentage, not exceed 60% at any time. A violation of this covenant could result in a default under the credit facility, which would permit the participating banks to restrict our ability to access the credit facility and require the immediate repayment of any outstanding advances under the credit facility.facility. As of December 31, 2008,2009, we were in full compliance with our debt covenants. The credit facility is with certain commercial lending institutions and is available for general corporate purposes.
 

7889
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Certain lenders that are a party to the credit facility have in the past performed investment banking, financial advisory, lending or commercial banking services for us, for which they have received customary compensation and reimbursement of expenses.
 
The credit facility does not restrict the payment of dividends on our common stock, except, if after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby.
 
Installment Payment DueDebt Offering   On February 27, 2009,—During 2007, we purchasedclosed an offering of $1 billion senior unsecured notes receiving net proceeds of $989 million, after deducting the discount and underwriting fees. The notes are due March 1, 2019, and pay interest semi-annually at 8¼%. Debt issuance costs of approximately $2 million were incurred and are being amortized to expense over the life of the debt issue. Substantially all of the net proceeds from the offering were used to repay outstanding indebtedness under our revolving credit facility maturing 2012. The notes are senior unsecured debt and rank pari passu with any of our other senior unsecured indebtedness with respect to the payment of both principal and interest.
Obligation Under FPSO Lease   On October 6, 2009, we entered into an agreement with an unrelated offshore technology provider for the construction and lease of a floating production, storage and offloading vessel (FPSO) to be used for the development of the Aseng field, offshore Equatorial Guinea. We serve as technical operator of the development project with a 40% working interestsinterest.
Construction of the FPSO is scheduled to be completed in 2012, at which time the FPSO will be delivered to Block I, offshore Equatorial Guinea, for the start-up of the Aseng field. The initial term of the lease is for a period of 15 years. We expect to account for the lease agreement as a capital lease. As a result, the FPSO will be included in oil and gas properties and the associated long-term obligation will be included in our balance sheet.  We expect that the Piceance basinlease obligation will total approximately $340 million, net to our 40% interest.  This amount represents our share of western Coloradothe expected present value of the future minimum lease payments, excluding executory costs, and is subject to change based on change orders implemented during the construction period, final accounting treatment and other factors.
Throughout the construction phase, we will include both the FPSO asset and associated long-term obligation in our balance sheet, based upon the percentage of construction completed at the end of each reporting period.
Monthly lease payments will exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations.  Annual lease payments, net to our 40% interest, are expected to total approximately $69 million per year for $75 million. After making cashyears 1-4 of the lease agreement, $43 million per year for years 5-7; and $8 million per year for the remaining years of the initial 15-year lease term.  These payments of $25 million at closingare also subject to change based on change orders implemented during the construction period and $25 million during 2008,other factors.
Installment Payment Due 2009   On May 11, 2009, we owe $25 million tomade the seller. The final $25 million installment is due on May 11, 2009.  The amount due is includedpayment to the seller of properties we purchased in short-term borrowings in our consolidated balance sheets.2007. Interest on the unpaid amount iswas due quarterly and accruesaccrued at a LIBOR rate plus .30%..30%. The interest rate was 4.18%1.51% at December 31, 2008.the date of payment.
 
Debt RepurchaseRepurchases— During 2008,   In 2009, we repurchased $11$5 million of our 7¼% Senior Debentures due August 1, 2097, recognizing a debt extinguishment gain of $1 million. In 2008, we repurchased $11 million of the same notes, recognizing a debt extinguishment gain of $4 million.
 
Annual Maturities—Maturities   Annual maturities of outstanding debt, excluding FPSO lease payments, are as follows:
 
 (in millions)  As of December 31, 2009 
2009 $25 
(millions)   
2010  -  $- 
2011  -   - 
2012  1,606   382 
2013  -   - 
2014  200 
Thereafter  639   1,434 
Total $2,270  $2,016 
 
Short-Term Borrowings—Our credit agreement is supplemented by short-term borrowings under various uncommitted credit lines used for working capital purposes. Uncommitted credit lines may be offered by certain banks from time to time at rates negotiated at the time of borrowing. Other than the installment payments discussed above, no short-term borrowings were outstanding at December 31, 20082009 or 2007.2008.
 

Note 9—
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Noble Energy, Inc.
Notes to Consolidated Financial Statements


Note 9. Income Taxes
 
Components of income (loss) before income taxes are as follows:
 
 Year Ended December 31,  Year Ended December 31, 
 2008  2007  2006  2009  2008  2007 
 (in millions) 
(millions)         
Domestic $1,032  $480  $402  $(808) $1,032  $480 
Foreign  1,029   888   694   544   1,029   888 
Total $2,061  $1,368  $1,096  $(264) $2,061  $1,368 
 
The income tax provision (benefit) consists of the following:
 
 Year Ended December 31,  Year Ended December 31, 
 2008  2007  2006  2009  2008  2007 
 (in millions) 
Current taxes         
(millions)         
Current Taxes         
Federal $45  $6  $80  $45  $45  $6 
State  1   1   6   1   1   1 
Foreign  306   125   138   117   306   125 
Total current  352   132   224 
Total Current  163   352   132 
                        
Deferred taxes            
Deferred Taxes            
Federal  363   186   144   (320)  363   186 
State  4   6   5   (5)  4   6 
Foreign  (8)  100   45   29   (8)  100 
Total deferred  359   292   194 
Total income tax provision $711  $424  $418 
Total Deferred  (296)  359   292 
Total Income Tax Provision (Benefit) $(133) $711  $424 
 



A reconciliation of the federal statutory tax rate to the effective tax rate is as follows:
 
  Year Ended December 31, 
  2009  2008  2007 
(percentages)         
Federal Statutory Rate  35.0   35.0   35.0 
Effect of            
Earnings of Equity Method Investees  11.3   (2.9)  (5.4)
State Taxes, Net of Federal Benefit  1.5   0.2   0.5 
Difference Between US and Foreign Rates  (1.4)  1.8   1.6 
Percentage Depletion in Excess of Basis  4.5   -   - 
Other, Net  (0.5)  0.4   (0.7)
Effective Rate  50.4   34.5   31.0 

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  Year Ended December 31, 
  2008 2007 2006 
  (amounts in percentages) 
Federal statutory rate  35.0  35.0  35.0 
Effect of          
Earnings of equity method investees  (2.9) (5.4) (4.2)
State taxes, net of federal benefit  0.2  0.5  1.3 
Difference between US and foreign rates  1.8  1.6  2.2 
Nondeductible goodwill  -  -  3.1 
Other, net  0.4  (0.7) 0.7 
Effective rate  34.5  31.0  38.1 

Deferred tax assets and liabilities resulted from the following:
 
  December 31, 
  2008  2007 
  (in millions) 
Deferred tax assets      
Loss carryforwards $36  $21 
Ecuador investment  18   - 
Accrued expenses  32   26 
Allowance for doubtful accounts  20   4 
Fair value of derivative instruments  -   177 
AOCL - pension asset/obligation  20   - 
Postretirement benefits  31   10 
Deferred compensation  63   61 
Foreign tax credits  51   82 
Other  27   14 
Total deferred tax assets  298   395 
Valuation allowance - foreign loss carryforwards  (35)  (18)
Valuation allowance - foreign tax credits  (51)  (57)
Valuation allowance - Ecuador investment
  (18)  - 
Net deferred tax assets  194   320 
Deferred tax liabilities        
Property, plant and equipment, principally due to differences in depreciation, amortization, lease impairment and abandonments
  (2,388)  (2,184)
Commodity derivative assets  (122)  - 
Other  -   11 
Total deferred tax liability  (2,510)  (2,173)
Net deferred tax liability $(2,316) $(1,853)
  December 31, 
  2009  2008 
(millions)      
Deferred Tax Assets      
Loss Carryforwards $49  $36 
Ecuador Investment  20   18 
Accrued Expenses  17   32 
Allowance for Doubtful Accounts  6   20 
Net Pension Obligation  34   36 
Postretirement Benefits  34   31 
Deferred Compensation  73   63 
Foreign Tax Credits  28   51 
Commodity Derivative Assets  54   - 
Other  35   27 
Total Deferred Tax Assets  350   314 
Valuation Allowance - Foreign Loss Carryforwards  (45)  (35)
Valuation Allowance - Foreign Tax Credits  (28)  (51)
Valuation Allowance - Ecuador Investment  (20)  (18)
Net Deferred Tax Assets  257   210 
Deferred Tax Liabilities        
Property, Plant and Equipment, Principally Due to Differences in Depreciation, Amortization, Lease Impairment and Abandonments  (2,302)  (2,388)
Commodity Derivative Assets  -   (138)
Total Deferred Tax Liability  (2,302)  (2,526)
Net Deferred Tax Liability $(2,045) $(2,316)
 
Net deferred tax liabilities were classified in the consolidated balance sheetsheets as follows:
 
  December 31, 
  2008  2007 
  (in millions) 
Deferred income tax asset $-  $131 
Deferred income tax liability - current  (142)  - 
Deferred income tax liability - noncurrent  (2,174)  (1,984)
Net deferred tax liability $(2,316) $(1,853)
  December 31, 
  2009  2008 
(millions)      
Deferred Income Tax Asset $32  $- 
Deferred Income Tax Liability - Current  (1)  (142)
Deferred Income Tax Liability - Noncurrent  (2,076)  (2,174)
Net Deferred Tax Liability $(2,045) $(2,316)
 
In assessing the realizability of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income in the appropriate tax jurisdictions during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, we believe it is more likely than not that we will realize the benefits of these deductible differences at December 31, 2008.2009. The amount of the deferred tax assets considered realizable could be reduced in the future if estimates of future taxable income during the carryforward period are reduced.
 


We have recognized deferred tax assets associated with foreign loss carryforwards. The tax effecteffects of these carryforwards decreased from $90 million in 2006 tototaled $18 million in 2007, and increased to $35 million in 2008. These losses2008, and increased to $47 million in 2009. Losses continue to be incurred on our projects in SurinameEquatorial Guinea and other new venture activities which are not yet commercial.commercial, and we also incurred a small loss in the UK. Therefore, a valuation allowance was provided against the full amount$45 million of the deferred tax assets.assets, excluding the UK loss which we expect to utilize in 2010. In 2006,2007, we incurredfully utilized a large taxable loss carryforward that arose in the UK in 2006 from accelerated write-offs allowed on our Dumbarton field development. No valuation allowance washad been provided against this loss carryforward, and it was fully utilized in 2007.carryforward.
 
Starting in 2005, we were able to claim a foreign tax credit for US federal income tax purposes. As of December 31, 2007, we hadWe have recorded a deferred tax asset of $11 million for certain foreign taxes related primarily to 2005. Because it was uncertain whether a credit could be claimed for those taxes under limitations imposed by the Internal Revenue Code, a valuation allowance of $11 million was provided against the deferred tax asset. However, this uncertainty was favorably resolved when we amended our 2005 and 2006 federal income tax returns in 2008. Therefore, both the deferred tax asset and the valuation allowance have been eliminated as of December 31, 2008. We have also recorded a deferred tax asset of $51$28 million for the future foreign tax credits associated with deferred tax liabilities recorded by foreign branch operations. A valuation allowance of $51$28 million has been provided against this deferred tax asset. Finally, a deferred

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Our effective tax asset of $18 million was recordedrate increased to 50% in 2009 as compared with 35% in 2008 forand is the futureresult of a tax benefit of an impairmentdivided by a pre-tax loss.  In the case of a foreign asset. However, this was fully offset by a valuation allowance.loss, our favorable permanent differences, such as income from equity method investees, have the effect of increasing the tax benefit which, in turn, increases the effective rate.
 
Our effective tax rate increased to 35% in 2008 as compared towith 31% in 2007 primarily due to the fact that pre-tax earnings increased by a proportionately greater amount than our excludible permanent differences. In addition, there was a rate increase due to (1) a partial shift of taxable income from lower rate jurisdictions such as Equatorial Guinea and Israel to higher rate jurisdictions, (2) the recording of US deferred taxes on the anticipated repatriation of foreign earnings as described below, and (3) the recording of an impairment of a foreign asset on which the tax benefit was offset by a valuation allowance.
 
Several factors resulted in a decrease in our effective tax rate for 2007. The major factor was that, in 2006, $100During first quarter 2009, we repatriated $180 million of goodwill write-off associated withaccumulated earnings of foreign subsidiaries and used the saleproceeds for debt repayment and general corporate purposes. The repatriation increased US tax expense by $13 million, of Gulf of Mexico shelf properties was not deductible, which increased the rate for that year. Other factors were an increase in deferred tax assets arising from foreign tax credits, a decrease in the Chinese tax rate, and the realization of additional income from equity method investees which is a favorable permanent difference in calculating the income tax expense.
We are currently reviewing the possibility of repatriating a portion of our international undistributed earnings. Therefore, as of December 31, 2008, we have recorded additional US deferred income taxes of $9 million on the portion of undistributed earnings of our foreign subsidiaries that are likely to be repatriated.was recorded in 2008. Repatriation of additional earnings in the future could result in a decrease in our net income and cash flows. As of December 31, 2008,2009, the accumulated undistributed earnings of the foreign subsidiaries on which no US taxes have been recorded were approximately $1.1$1.2 billion. Upon distribution of additional earnings in the form of dividends or otherwise, we would likely be subject to US income taxes and foreign withholding taxes. It is not practicable, however, to estimatedetermine precisely the amount of taxes that may be payable on the eventual remittance of these earnings because of the possible application of US foreign tax credits. Although we are currently claiming foreign tax credits, we may not be in a credit position when any future remittance of foreign earnings takes place, or the limitations imposed by the Internal Revenue Code and IRS Regulations may not allow the credits to be utilized during the applicable carryback and carryforward periods. However, if full use of tax credits is assumed, we estimate that the future US taxes on eventual remittance would be approximately $230 million.
 
DuringIn 2007, China’s legislature, the National People’s Congress, enacted the China Corporate Income Tax Law.  This new legislation decreased our tax rate in China from 33% to 25% starting in 2008.  The2008, resulting in a $2 million reduction in deferred tax liability for China as of December 31, 2006 was revised during 2007 to reflect the new rate, which decreased deferred tax expense by $2 million.expense.
 
Adoption of FIN 48 and FSP FIN 48-1US GAAP for Accounting for Uncertainty in Income Taxes   —As discussed in Note 2—Significant Accounting Policies, we adopted FIN 48 and FSP FIN 48-1US GAAP for accounting for uncertainty in income taxes, including unrecognized tax benefits as of January 1, 2007. The adoption had no effect on our financial position or results of operations. We dodid not have significant unrecognized tax benefits resulting from differences between positions taken in tax returns and amounts recognized in the financial statements as of December 31, 2008.2008 or 2009. Our policy is to recognize any interest and penalties related to unrecognized tax benefits in income tax expense. WeHowever, we did not accrue interest or penalties at December 31, 2008 or 2009, because the jurisdiction in which we have unrecognized tax benefits does not currently impose interest on underpayments of tax and we believe that we are below the minimum statutory threshold for imposition of penalties. We do not expect that the total amount of unrecognized tax benefits will significantly increase or decrease during the next 12 months.
 


In our major tax jurisdictions, the earliest years remaining open to examination are as follows:
Earliest Year
Remaining Open
Tax Jurisdictionto Examination
United States2005
Equatorial Guinea2006
China2006
Israel2000
UK2006
the Netherlands2005
US – 2006, Equatorial Guinea – 2007, China – 2006, Israel – 2000, UK – 2007 and the Netherlands – 2005.
 
Note 10—10.  Asset Retirement Obligations
 
Asset retirement obligations consist of estimated costs of dismantlement, removal, site reclamation and similar activities associated with our oil and gas properties. An asset retirement obligation and the related asset retirement cost are recorded when an asset is first constructed or purchased. The asset retirement cost is determined and discounted to present value using a credit-adjusted risk-free rate. After initial recording the liability is increased for the passage of time, with the increase being reflected as accretion expense in the statement of operations. Subsequent adjustments in the cost estimate are reflected in the liability and the amounts continue to be amortized over the useful life of the related long-lived asset.
 
Changes in asset retirement obligations are as follows:
 
  Year Ended December 31, 
  2009  2008 
(in millions)      
Asset Retirement Obligations, Beginning of Period $211  $144 
Liabilities Incurred in Current Period  22   15 
Liabilities Settled in Current Period  (36)  (33)
Revisions  21   75 
Accretion Expense  14   10 
Asset Retirement Obligations, End of Period $232  $211 
For the year ended December 31, 2009, liabilities incurred related primarily to properties in the deepwater Gulf of Mexico, the Aseng field in Equatorial Guinea and North Sea projects.   Liabilities settled related primarily to properties in the Main Pass and Viosca Knoll areas of the Gulf of Mexico.  Revisions relate to the Main Pass asset and a deepwater Gulf of Mexico property.

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

  Year Ended  
  December 31,  
  2008   2007  
  (in millions)  
Asset retirement obligations, beginning of year $144 $  196  
Liabilities incurred in current period  15   9  
Liabilities settled in current period  (33)  (177) 
Revisions  75   108  
Accretion expense  10   8  
Asset retirement obligations, end of year $211 $ 144  
         
Current portion $27 $ 13  
Noncurrent portion  184   131  

For the year ended December 31, 2008, liabilities settled relaterelated primarily to onshore US and Gulf of Mexico assets. Revisions include $15 million related to our Main Pass asset held for sale at December 31, 2008. The remaining revisions resulted from changes in estimated timing of actual abandonment and overall cost increases for the North Sea assets ($18 million), onshore US and Gulf of Mexico assets ($38 million) and Israel and other locations ($4 million).
For the year ended December 31, 2007, approximately $125 million of liabilities settled and $64 million of revisions related to hurricane damage to the Gulf of Mexico Main Pass assets. The remainder of the liabilities settled and revisions resulted primarily from changes in estimated timing of actual abandonment and overall cost increases for Gulf of Mexico assets.
 
Accretion expense is included in depreciation, depletion and amortization expense in the consolidated statements of operations.
 
Note 11—11.  Equity Method Investments
 
Investments accounted for under the equity method consist primarily of the following:
 
 ·45% interest in Atlantic Methanol Production Company, LLC (AMPCO), which owns and operates a methanol plant and related facilities in Equatorial Guinea; and
 ·28% interest in Alba Plant LLC (Alba Plant), which owns and operates a liquefied petroleum gas processing plant in Equatorial Guinea.
 
Equity method investments are included in other noncurrent assets in the consolidated balance sheets, and our share of earnings is reported as income from equity method investees in the consolidated statements of operations. Our share of income taxes incurred directly by the equity method investees is reported in income from equity method investments and is not included in our income tax provision in our consolidated statements of operations. At December 31, 2008,2009, our retained earnings included $114$123 million related to the undistributed earnings of equity method investees.
 


The carrying value of our AMPCO investment is $25$24 million higher than the underlying net assets of the investee.  $13$12 million of the difference relates to capitalized interest which is being amortized into earnings over the remaining useful life of the plant.  The remaining $12 million relates to a note receivable from our funding a portion of the local government’s share of the plant’s development.  The note receivable is being recovered through distributions from AMPCO.
 
Equity method investments are as follows:
 
  December 31, 
  2009  2008 
(millions)      
Equity Method Investments      
AMPCO $180  $190 
Alba Plant  111   106 
Other  12   15 
Total Equity Method Investments $303  $311 

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Noble Energy, Inc.
Notes to Consolidated Financial Statements

  December 31, 
  2008 2007 
  (in millions) 
Equity method investments     
AMPCO $190 $200 
Alba Plant  106  142 
Other  15  15 
Total equity method investments $311  357 

Summarized, 100% combined financial information for equity method investees is as follows:
 
     December 31, 
    2008 2007 
    (in millions) 
Balance sheet information       
Current assets   $283 $408 
Noncurrent assets    783  814 
Current liabilities    248  273 
Noncurrent liabilities    43  31 
          
  Year Ended December 31, 
  2008 2007 2006 
  (in millions) 
Statements of operations information         
Operating revenues $1,022 $934 $702 
Less cost of goods sold  250  220  202 
Gross margin  772  714  500 
Less other expense  37  36  48 
Less income tax expense (1)
  183  44  23 
Net income $552 $634 $429 
     December 31, 
     2009  2008 
(millions)         
Balance Sheet Information         
Current Assets    $269  $283 
Noncurrent Assets     751   783 
Current Liabilities     187   248 
Noncurrent Liabilities     59   43 
            
  Year Ended December 31, 
  2009   2008   2007 
(millions)           
Statements of Operations Information           
Operating Revenues $632  $1,022  $934 
Operating Expenses  264   301   270 
Operating Income  368   721   664 
Other Income, Net  (13)  (14)  (14)
Income Before Income Taxes  381   735   678 
Income Tax Provision (1)
  95   183   44 
Net Income $286  $552  $634 
 
(1)The increase in income tax expense in 2008 is due to the expiration of the Alba Plant tax holiday.

Note 12 –12.  Benefit Plans
 
Pension Plan and Other Postretirement Benefit Plans—Plans   We have a noncontributory, tax-qualified defined benefit pension plan covering employees who were hired prior to May 1, 2006.  The benefits are based on an employee’s years of service and average earnings for the 60 consecutive calendar months of highest compensation. Our funding policy has been to make annual contributions equal to at least the minimum required contribution, but no greater than the maximum deductible for federal income tax purposes. We also have an unfunded, nonqualified restoration plan that provides the pension plan formula benefits that cannot be provided by the qualified pension plan because of pay deferrals and the compensation and benefit limitations imposed on the pension plan by the Internal Revenue Code of 1986, as amended. We sponsor other plans for the benefit of our employees and retirees, which include medical and life insurance benefits. We use a December 31 measurement date for the plans.
 
Former Patina employees began participation in the pension plan and the restoration plan on January 1, 2006, with vesting service from their original Patina hire date and credited service for benefit accruals starting January 1, 2006. Additionally, all former Patina employees were covered under the medical and life insurance plans effective January 1, 2006.
On December 31, 2006, we adopted SFAS 158, which required us toWe recognize the funded status (the difference between the fair value of plan assets and the benefit obligation) of our defined benefit pension, restoration and other postretirement benefit plans in the consolidated balance sheet,sheets, with a corresponding adjustment to AOCL, net of tax.


The adjustment toamount remaining in AOCL at adoption represented theDecember 31, 2009 represents unrecognized net actuarial loss, unrecognized prior service cost, and unrecognized net transition obligation remaining from the initial adoption of SFAS No. 87, “Employers’ AccountingUS GAAP for Pensions”employers’ accounting for pensions and SFAS No. 106, “Employers’ Accounting for Post-Retirement Benefits Other Than Pensions”.other postretirement benefits. These amounts are currently being recognized as net periodic benefit cost pursuant to our historical accounting policy for amortizing such amounts. Further,Any actuarial gains and losses that arise in periods subsequentduring the plan year, but which are not required to adoption and are notbe recognized as net periodic benefit cost in the same periodsperiod, are recognized as a component of AOCL. The adoption


Changes in the benefit obligation and plan assets of the pension, restoration and other postretirement benefit plans are as follows at December 31:
 
  Retirement and  Medical and 
  Restoration Plans  Life Plans 
  2008  2007  2008  2007 
  (in millions) 
Change in benefit obligation            
Benefit obligation at beginning of year $188  $175  $22  $22 
Service cost  12   12   2   2 
Interest cost  12   10   1   1 
Amendments  -   8   -   - 
Benefits paid  (17)  (6)  (1)  (1)
Actuarial (gain) loss  (1)  (11)  (2)  (2)
Benefit obligation at end of year  194   188   22   22 
Change in plan assets                
Fair value of plan assets at beginning of year  155   137   -   - 
Actual return on plan assets  (43)  13   -   - 
Employer contributions  37   11   1   1 
Benefits paid  (17)  (6)  (1)  (1)
Fair value of plan assets at end of year  132   155   -   - 
Funded status                
Funded status at end of year  (62)  (33)  (22)  (22)
Net amount recognized in consolidated balance sheets (after adoption of FAS 158)
  (62)  (33)  (22)  (22)
Amounts recognized in consolidated balance sheets consist of:                
Current liabilities  (2)  (3)  (1)  (1)
Noncurrent liabilities  (60)  (30)  (21)  (21)
Net amount recognized in consolidated balance sheets (after adoption of FAS 158)
  (62)  (33)  (22)  (22)
Amounts not yet reflected in net periodic benefit cost and included in AOCL                
Transition obligation  -   (1)  -   - 
Prior service (cost) credit  (3)  (3)  5   6 
Accumulated loss  (86)  (34)  (10)  (14)
AOCL  (89)  (38)  (5)  (8)
Cumulative employer contributions in excess of net periodic benefit cost  27   5   (17)  (14)
Net amount recognized in consolidated balance sheet (after adoption of FAS 158) $(62)  (33) $(22)  (22)
  Retirement and Restoration Plans  Medical and Life Plans 
  2009  2008  2009  2008 
(millions)            
Change in Benefit Obligation            
Benefit Obligation at Beginning of Year $194  $188  $22  $22 
Service Cost  12   12   2   2 
Interest Cost  11   12   1   1 
Benefits Paid  (13)  (17)  (1)  (1)
Plan Amendments (1)
  -   -   (2)  - 
Actuarial (Gain) Loss  24   (1)  1   (2)
Benefit Obligation at End of Year  228   194   23   22 
Change in Plan Assets                
Fair Value of Plan Assets at Beginning of Year  132   155   -   - 
Actual Return on Plan Assets  33   (43)  -   - 
Employer Contributions  20   37   1   1 
Benefits Paid  (13)  (17)  (1)  (1)
Fair Value of Plan Assets at End of Year  172   132   -   - 
Funded Status                
Funded Status at End of Year  (56)  (62)  (23)  (22)
Net Amount Recognized in Consolidated Balance Sheets  (56)  (62)  (23)  (22)
Amounts Recognized in Consolidated Balance Sheets Consist of             
Current Liabilities  (2)  (2)  (1)  (1)
Noncurrent Liabilities  (54)  (60)  (22)  (21)
Net Amount Recognized in Consolidated Balance Sheets  (56)  (62)  (23)  (22)
Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in AOCL         
Prior Service (Cost) Credit  (3)  (3)  7   5 
Accumulated Loss  (88)  (86)  (11)  (10)
AOCL  (91)  (89)  (4)  (5)
Cumulative Employer Contributions in Excess of Net Periodic Benefit Cost  35   27   (19)  (17)
Net Amount Recognized in Consolidated Balance Sheets $(56) $(62) $(23) $(22)

(1) Plan amendments relate to an increase in the monthly retiree contributions for the medical and life plan.

8496
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Net periodic benefit cost recognized for the pension, restoration and other postretirement benefit plans is provided in the table below:was as follows:
 
  Retirement and  Medical and 
  Restoration Plans  Life Plans 
  Year Ended December 31,  Year Ended December 31, 
  2008  2007  2006  2008  2007  2006 
  (in millions) 
Components of net periodic benefit cost                  
Service cost $12  $12  $12  $2  $2  $2 
Interest cost  12   10   9   1   1   1 
Expected return on plan assets  (12)  (11)  (9)  -   -   - 
Amortization of prior  service (credit) cost  -   -   -   (1)  (1)  - 
Amortization of net loss  2   3   3   1   1   1 
Net periodic benefit cost $14  $14  $15  $3  $3  $4 
Other changes recognized in AOCL                        
Prior service cost arising during period $-  $8   *  $-  $-   * 
Net loss (gain) arising during period  53   (13)  *   (3)  (3)  * 
Amortization of prior service credit  -   -   *   1   1   * 
Amortization of net loss  (2)  (3)  *   (1)  (1)  * 
Total recognized in  AOCL $51  $(8)  *  $(3) $(3)  * 
Expected amortizations for next fiscal year                        
Amortization of prior service cost (credit) $-  $-  $(1) $(1) $(1) $(1)
Amortization of net loss  2   2   3   1   1   1 
                         
Weighted-average assumptions used to determine benefit obligations                        
Discount rate (1)
  6.00% / 6.25%  6.50%  5.75%  6.25%  6.25%  5.75% 
Rate of compensation increase  5.00%  5.00%  5.00%  -   -   - 
                         
Weighted-average assumptions used to determine net periodic benefit costs                        
Discount rate (2)
   6.50%   5.75%    5.50% / 6.25%    6.25%    5.75%    5.50% / 6.25% 
Expected long-term rate of return on plan assets  8.25%  8.25%  8.25%  -   -   - 
Rate of compensation increase  5.00%  5.00%  5.00%  -   -   - 
  Retirement and Restoration Plans  Medical and Life Plans 
  Year Ended December 31,  Year Ended December 31, 
  2009  2008  2007  2009  2008  2007 
(millions)                  
Components of Net Periodic Benefit Cost                  
Service Cost $12  $12  $12  $2  $2  $2 
Interest Cost  11   12   10   1   1   1 
Expected Return on Plan Assets  (14)  (12)  (11)  -   -   - 
Amortization of Prior Service (Credit) Cost  -   -   -   (1)  (1)  (1)
Amortization of Net Loss  3   2   3   1   1   1 
Net Periodic Benefit Cost $12  $14  $14  $3  $3  $3 
Other Changes Recognized in AOCL                        
Prior Service Cost Arising During Period $-  $-  $8  $(2) $-  $- 
Net Loss (Gain) Arising During Period  5   53   (13)  1   (3)  (3)
Amortization of Prior Service Credit  -   -   -   1   1   1 
Amortization of Net Loss  (3)  (2)  (3)  (1)  (1)  (1)
Total Recognized in  AOCL $2  $51  $(8) $(1) $(3) $(3)
Expected Amortizations for Next Fiscal Year                        
Amortization of Prior Service Cost (Credit) $-  $-  $-  $(1) $(1) $(1)
Amortization of Net Loss  5   2   2   1   1   1 
Weighted-Average Assumptions Used to Determine Benefit Obligations                        
Discount Rate (1)
  6.00%  6.00% / 6.25%  6.50%  5.50%  6.25%  6.25 %
Rate of Compensation Increase  5.00%  5.00%  5.00%  -   -   - 
Weighted-Average Assumptions Used to Determine Net Periodic Benefit Costs                        
Discount Rate (1)
  6.00% / 6.25%  6.50%  5.75%  6.25%  6.25%  5.75%
Expected Long-Term Rate of  Return on Plan Assets  8.00%  8.25%  8.25%  -   -   - 
Rate of Compensation Increase  5.00%  5.00%  5.00%  -   -   - 
*Not applicable due to change in method of accounting for defined benefit and other post retirement plans.
(1)The discount rate wasrates used to determine benefit obligations at December 31, 2008 and net periodic benefit costs for the year ended December 31, 2009 were 6.00% for the retirement plan and 6.25% for the restoration plan at December 31, 2008.plan.
(2)The net periodic benefit cost was remeasured at May 1, 2006 using a discount rate of 6.25%, due to changes in plan provisions.

 
Additional disclosures for the retirement and restoration plans are as follows:
 
  Retirement and 
  Restoration Plans 
  2008 2007 
   (in millions) 
Accumulated benefit obligation $169 $163 
Information for pension plans with projected benefit obligations in excess of plan assets
       
Projected benefit obligation  194  188 
Fair value of plan assets  132  155 
Information for pension plans with accumulated benefit obligations in excess of plan assets       
Accumulated benefit obligation  169  25 
Fair value of plan assets  132  - 

   December 31, 
   2009  2008 
(millions)       
Accumulated Benefit Obligation $197 $169 
Information for Pension Plans With Projected Benefit Obligations in Excess of Plan Assets   
Projected Benefit Obligation        228       194 
Fair Value of Plan Assets        172       132 
Information for Pension Plans With Accumulated Benefit Obligations in Excess of Plan Assets   
Accumulated Benefit Obligation          31       169 
Fair Value of Plan Assets            -       132 
 


In selecting the assumption for expected long-term rate of return on assets, we consider the average rate of earnings expected on the funds to be invested to provide for plan benefits. This includes considering the plan’s asset allocation, historical returns on these types of assets, the current economic environment and the expected returns likely to be earned over the life of the plan. We assume the long-term asset mix will be consistent with a target asset allocation of 70% equity and 30% fixed income, with a range of plus or minus 10% acceptable degree of variation in the plan’s asset allocation. Based on these factors we assumed an average of 8.25%8.00% per annum over the life of the plan for the calculation of 20082009 net periodic benefit cost. The assumption will be reduced to 8.00%7.50% for the calculation of 20092010 net periodic benefit cost. No plan assets are expected to be returned to us during 2009.in 2010.

97
Noble Energy, Inc.
Notes to Consolidated Financial Statements


In order to determine an appropriate discount rate at December 31, 2008,2009, we performed an analysis of the Citigroup Pension Discount Curve (the CPDC) as of that date for each of our plans. The CPDC uses spot rates that represent the equivalent yield on high quality, zero coupon bonds for specific maturities. We used these rates to develop an equivalent single discount rate based on our plans’ expected future benefit payment streams and duration of plan liabilities. A 1% increase in the discount rate would have resulted in a decrease in net periodic benefit cost of approximately $2 million in 2008.2009. A 1% decrease in the discount rate would have resulted in an increase in net periodic benefit cost of approximately $2 million in 2008.2009.
 
Assumed health care cost trend rates were as follows at December 31:follows:
 
  2008  2007 
Health care cost trend rate assumed for next year 8%  9% 
Rate to which the cost trend rate is assumed to decline (ultimate trend rate) 5%  5% 
Year rate reaches ultimate trend rate 2012  2012 
  December 31, 
  2009  2008 
Health Care Cost Trend Rate Assumed for Next Year  8.00%  8.00%
Rate to Which the Cost Trend Rate is Assumed to Decline (Ultimate Trend Rate)  4.50%  5.00%
Year Rate Reaches Ultimate Trend Rate  2030   2012 
 
Assumed health care cost trend rates have a significant effect on the amounts reported for health care plans. A one-percentage-point change in assumed health care cost trend rates would have the following effects:
 
  1% Increase  1% Decrease 
  (in millions) 
Effect on total service and interest cost components for 2008 $-  $- 
Effect on year-end 2008 postretirement benefit obligation  2   (2)
  1% Increase  1% Decrease 
(millions)      
Effect on Total Service and Interest Cost Components for 2009 $-  $- 
Effect on Year-End 2009 Postretirement Benefit Obligation  3   (2)

Weighted-average asset allocations for the tax-qualified defined benefit pension plan are as follows:
 
 Target       
 Allocation  Plan Assets  Target Allocation  Plan Assets 
 2009  2008  2007  2010  2009  2008 
Asset Category                  
Equity securities  70%   65%   70% 
Fixed income  30%   35%   30% 
Equity Securities  70%  73%  65%
Fixed Income  30%  27%  35%
Total  100%   100%   100%   100%  100%  100%

The investment policy for the tax-qualified defined benefit pension plan is determined by an employee benefits committee (the committee) with input from a third-party investment consultant. Based on a review of historical rates of return achieved by equity and fixed income investments in various combinations over multi-year holding periods and an evaluation of the probabilities of achieving acceptable real rates of return, the committee has determineddetermined the target asset allocation deemed most appropriate to meet the immediate and future benefit payment requirements for the plan and to provide a diversification strategy which reduces market and interest rate risk. The fixed income allocation is expected to directionally track a portion of the plan's liabilities, thus reducing overall plan interest rate risk. A 1% increase (decrease) in the expected return on plan assets would have resulted in a (decrease) increase, respectively, in net periodic benefit cost of approximately $2 million in 2008.2009.
 
We base our determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2008,2010, we had cumulative asset gains (losses) of approximately $3$(16) million, which remain to be recognized in the calculation of the market-related value of assets.
 



98
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Additional fair value disclosures about plan assets are as follows:
   Fair Value Measurements at December 31, 2009 
   Total  Quoted Prices in Active Markets for Identical Assets (Level 1)Significant Observable Inputs (Level 2)  Significant Unobservable Inputs (Level 3) 
(millions)             
Asset Category             
Federal Money Market Funds $ 2 $ 2 $- $- 
Mutual Funds             
Equity (Common Stocks)         76          76           -          - 
Fixed Income         47          47           -          - 
Common Collective Trust Funds         47            -         47          - 
Total $ 172 $ 125 $47 $- 
Additional information about plan assets, including methods and assumptions used to estimate the fair values of plan assets, is as follows:
Contributions—Federal Money Market Funds    Investments in federal money market funds consist of portfolios of high quality fixed income securities (such as US Treasury securities) which, generally, have maturities less than one year.  The fair value of these investments is based on quoted market prices for identical assets as of the measurement date.
Mutual Funds   Investments in mutual funds consist of diversified portfolios of common stocks and fixed income instruments.  The common stock mutual funds are diversified by market capitalization and investment style as well as economic sector and industry.  The fixed income mutual funds are diversified primarily in government bonds, mortgage backed securities, and corporate bonds, most of which are rated investment grade.  The fair values of these investments are based on quoted market prices for identical assets as of the measurement date.
Common Collective Trust Funds    Investments in common collective trust funds consist of common stock investments in both US and non-US equity markets.  Portfolios are diversified by market capitalization and investment style as well as economic sector and industry. The investments in the non-US equity markets are used to further enhance the plan’s overall equity diversification which is expected to moderate the plan’s overall risk volatility.  In addition to the normal risk associated with stock market investing, investments in foreign equity markets may carry additional political, regulatory, and currency risk which is taken into account by the committee in its deliberations. The fair value of these investments is based on quoted prices for similar assets in active markets. All of the investments in Common Collective Trust Funds represent exchange-traded securities with readily observable prices.
Contributions   As a result of previous contributions made to the pension plan, there are no required contributions expected during 2009. Duringin 2010. In January 2009,2010, we made a voluntary contribution of $1$2 million to the pension plan. We may make additional contributions to our pension plan during the year. We expect to make cash contributions of approximately $2 million to the unfunded restoration plan and $1 million to the medical and life plans during 2009.


in 2010. The amounts expected to be contributed to the unfunded restoration and medical and life plans equal expected benefit payments from those plans. (unaudited).
 
Estimated Future Benefit Payments—Payments   As of December 31, 2008,2009, the following future benefit payments are expected to be paid:
 
 Retirement and  Medical and  Retirement and Restoration Plans  Medical and Life Plans 
 Restoration Plans  Life Plans 
 (in millions) 
      
2009 $18  $1 
(millions)     
2010 13   2  $14 $ 1 
2011 16   2            18       1 
2012 17   2            20        1 
2013 16   2            19       2 
Years 2014 to 2018  99   14 
2014           21       2 
Years 2015 to 2019          120     11 
 
The estimate of expected future benefit payments is based on the same assumptions used to measure the benefit obligation at December 31, 20082009 and includes estimated future employee service.
 
401(k) Plan—Plan   We sponsor a 401(k) savings plan. All regular employees are eligible to participate. We make contributions to match employee contributions up to the first 6% of compensation deferred into the plan, and certain profit sharing contributions for employees hired on or after May 1, 2006, based upon their ages and salaries. We made cash contributions of $9 million in 2009, $7 million in 2008, and $6 million in 2007, and $4 million in 2006.2007.
 
Deferred Compensation Plans—Plans   In connection with the Patina Merger, we acquired the assets and assumed the liabilities related to a Patina shareholder-approved non-qualified deferred compensation plan. This plan was available to officers and certain managers of Patina and allowed participants to defer all or a portion of their salary and annual bonuses (either in cash or common stock). Participant-directed investments are held in a rabbi trust and are available to satisfy the claims of our creditors in the event of bankruptcy or insolvency. Participants may elect to receive distributions in either cash or shares of our common stock. We account for the deferred compensation plan in accordance with EITF 97-14, “Accounting for Deferred Compensation Arrangements Where Amounts Earned are Held in a Rabbi Trust and Invested” (EITF 97-14). Components of the rabbi trust are as follows:

99
Noble Energy, Inc.
Notes to Consolidated Financial Statements


 
  December 31, 
  2008  2007 
  (in millions, except share amounts) 
Rabbi trust assets      
Mutual fund investments $71  $107 
Noble Energy common stock (at market value) (1)
  52   87 
Total rabbi trust assets  123   194 
Liability under Patina deferred compensation plan $123  $194 
Number of shares of Noble Energy common stock held by rabbi trust  1,051,032   1,101,032 
  December 31, 
  2009  2008 
(millions, except share amounts)      
Rabbi Trust Assets      
Mutual Fund Investments $93  $71 
Noble Energy Common Stock (at Fair Value) (1)
  75   52 
Total Rabbi Trust Assets  168   123 
Liability Under Patina Deferred Compensation Plan $168  $123 
Number of Shares of Noble Energy Common Stock Held by Rabbi Trust  1,049,140   1,051,032 
 
(1)Shares of Noble Energyour common stock are accounted for as treasury stock and recorded at cost in the consolidated balance sheets.
 
Assets of the rabbi trust, other than our common stock, are invested in certain mutual funds that cover an investment spectrum ranging from equities to money market instruments. These mutual funds have published market prices and are reported at marketfair value. We account for these investments in accordance with SFAS No. 115, “Accounting for Certain Investments in DebtSee Note 5. Fair Value Measurements and Equity Securities.”Disclosures. The mutual funds are included in the mutual fundsfund investments account in other noncurrent assets in the consolidated balance sheets.
 
Shares of our common stock held by the rabbi trust are accounted for as treasury stock (recorded at cost) in the shareholders’ equity section of the consolidated balance sheets. The amounts payable to the plan participants are included in other noncurrent liabilities in the consolidated balance sheets and include the market value of the shares of our common stock. Approximately one million shares, or 95%, of our common stock held in the plan at December 31, 20082009 were attributable to a member of our Board of Directors. Plan participants sold 1,892 shares of  our common stock in 2009, 50,000 shares of common stock duringin 2008, and no shares during 2007, and 1,067,948 shares during 2006.in 2007. Proceeds were invested in mutual funds. Distributions to plan participants totaled $1 million in 2008 and $2 million in 2007, and $0.5 million2007. Distributions to plan participants were de minimis in 2006.2009.
 


In accordance with EITF 97-14, allAll fluctuations in market value of the deferred compensation liability have been reflected in other non-operating (income) expense, net in the consolidated statements of operations. We recognized deferred compensation expense of $23 million in 2009, deferred compensation income of $32 million in 2008, and deferred compensation expense of $33 million in 2007 and $16 million in 2006.2007.
 
We also maintain an unfunded deferred compensation plan for the benefit of certain of our employees. A deferredDeferred compensation liabilityliabilities of $45 million and $36 million waswere outstanding at December 31, 2009 and 2008, respectively, under the unfunded plan.

Note 13 –13.   Stock-Based Compensation
As discussed in Note 2—Summary of Significant Accounting Policies, effective January 1, 2006, we adopted the fair value recognition provisions for stock-based awards granted to employees. SFAS 123(R) requires companies to recognize in the statement of operations the grant-date fair value of stock options and other stock-based compensation issued to employees. We recognize the expense of all stock-based awards on a straight-line basis over the employee’s requisite service period (generally the vesting period of the award).
 
We recognized total stock-based compensation expense as follows:
 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Stock-Based Compensation Expense Included in         
General and Administrative Expense $36  $38  $25 
Exploration Expense and Other  13   1   2 
Total Stock-Based Compensation Expense $49  $39  $27 
Tax Benefit Recognized $(17) $(15) $(10)

100
Noble Energy, Inc.
Notes to Consolidated Financial Statements

  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Stock-based compensation expense included in         
General and administrative expense $38  $25  $11 
Exploration expense and other  1   2   1 
Total stock-based compensation expense $39  $27  $12 
             
Tax benefit recognized $(15) $(10) $(4)

Stock Option and Restricted Stock Plans and Incentive Plan—Our stock option and restricted stock plans and incentive plan are described below.
 
1992 Stock Option and Restricted Stock Plan
1992 Stock Option and Restricted Stock PlanUnder the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, as amended (the 1992 Plan), the Compensation, Benefits and Stock Option Committee of the Board of Directors (the Committee) may grant stock options and award restricted stock to our officers or other employees and those of our subsidiaries. DuringIn 2007, our stockholders approved an amendment to the 1992 Plan that increased the maximum number of shares of our common stock that may be issued from 18,500,00018 million to 22,000,00022 million shares. In 2009, our stockholders approved an amendment to the 1992 Plan that increased the maximum number of shares of our common stock that may be issued from 22 million to 24 million shares. At December 31, 2008, 10,469,6232009, 12,263,457 shares of our common stock were reserved for issuance, including 4,698,7884,706,057 shares available for future grants and awards, under the 1992 Plan.
 
1992 Plan Stock Options—Stock options are issued with an exercise price equal to the market price of our common stock on the date of grant, and are subject to such other terms and conditions as may be determined by the Committee. Unless granted by the Committee for a shorter term, the options expire ten years from the grant date. Option grants generally vest ratably over a three-year period.
 
1992 Plan Restricted Stock—Restricted stock awards made under the 1992 Plan are subject to such restrictions, terms and conditions, including forfeitures, if any, as may be determined by the Committee. Restricted stock awards generally vest over three years. In 2009, we began making grants of restricted stock under the 1992 Plan that time-vest 20% after year one, an additional 30% after year two and the remaining 50% after year three.
 
2004 Long-Term Incentive Plan
2004 Long-Term Incentive Plan   Under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (the 2004 LTIP), the Committee may make incentive awards to our key employees and those of our subsidiaries. Incentive compensation is based upon the attainment of specific market and performance goals established by the Committee. Awards may be in the form of stock options or restricted stock or in the form of performance units or other incentive measurements providing for the payment of bonuses in cash, or in any combination thereof, as determined by the Committee in its discretion. Stock options granted and restricted stock awarded under the 2004 LTIP are granted and awarded pursuant to the terms of the 1992 Plan. These awards are accounted for in accordance with the provisions of SFAS 123(R)US GAAP for stock-based compensation, which provides for the grant-date fair value of the awards to be recognized in the statement of operations over the service period. Our cash based performance units, arewhich were issued in 2006 and vested in 2009, were accounted for under SFAS No. 5, “Accountingin accordance with US GAAP for Contingencies” and are excluded from the provisions of SFAS 123(R).contingencies.
 


2005 Stock Plan for Non-Employee Directors
The 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (the 2005 Plan) provides for grants of stock options and awards of restricted stock to our non-employee directors. The 2005 Plan superseded and replaced the 1988 Nonqualified Stock Option Plan for Non-Employee Directors. The total number of shares of our common stock that may be issued under the 2005 Plan is 800,000. At December 31, 2008, 739,2042009, 730,349 shares of our common stock were reserved for issuance, including 620,675568,841 shares available for future grants and awards under the 2005 Plan.
 
2005 Plan Stock Options—The 2005 Plan provides for the granting to a non-employee director of up to a maximum of 11,200 stock options on the date of election to the Board of Directors, annual grants of 2,800 options per non-employee director on February 1 of each year, and discretionary grants by the Board of Directors (with the February 1 annual and the discretionary grants made to a non-employee director during any calendar year being limited to a combined maximum of 11,200 options). Options are issued with an exercise price equal to the market price of our common stock on the date of grant and may be exercised one year after the date of grant. The options expire ten years from the date of grant.
 
2005 Plan Restricted Stock—The 2005 Plan also provides for the awarding to a non-employee director of up to a maximum of 4,800 shares of restricted stock on the date of election to the Board of Directors, annual awards of 1,200 shares of restricted stock per non-employee director on February 1 of each year, and discretionary awards by the Board of Directors (with the February 1 annual and the discretionary awards made to a non-employee director during any calendar year being limited to a combined maximum of 4,800 shares of restricted stock). Restricted stock is restricted for a period of at least one year from the date of award.
 

1988 Nonqualified Stock Option Plan for Non-Employee Directors
101
Noble Energy, Inc.
Notes to Consolidated Financial Statements


1988 Nonqualified Stock Option Plan for Non-Employee Directors   The 1988 Nonqualified Stock Option Plan for Non-Employee Directors of Noble Energy, Inc., as amended, (the 1988 Plan) provided for the issuance of stock options to our non-employee directors. Options issued under the 1988 Plan may be exercised one year after grant and expire ten years from the grant date. The 1988 Plan provided for the granting of a fixed number of stock options to each non-employee director annually (10,000 stock options for the first calendar year of service and 5,000 stock options for each year thereafter) on February 1 of each year. The 1988 Plan was terminated in 2005, and no additional options can be granted thereunder.
 
Patina Stock Option Plans
Patina Stock Option Plans   Patina maintained a shareholder approved stock option plan for employees (the Patina Employee Plan) that provided for the issuance of options at prices not less than fair market value at the date of grant. Patina also maintained a shareholder approved stock grant and option plan for non-employee directors (the Patina Directors’ Plan). The Patina Directors’ Plan provided for stock options to be granted to each non-employee director upon appointment and upon annual re-election thereafter. Upon completion of the Patina Merger, all unvested stock options outstanding under the Patina Employee Plan and the Patina Directors’ Plan became fully vested, and all outstanding options were converted into options to purchase our common stock. The remaining Patina options expire five years from the date of grant.in 2010.
 
Stock Option Grants—The fair value of each stock option granted was estimated on the date of grant using a Black-Scholes-Merton option valuation model that used the assumptions described below:
 
 ·
Expected term - The expected term represents the period of time that options granted are expected to be outstanding, which is the grant date to the date of expected exercise or other expected settlement for options granted. The hypothetical midpoint scenario we use considers our actual exercise and post-vesting cancellation history and expectations for future periods, which assumes that all vested, outstanding options are settled halfway between their vesting date and their expiration date.
 ·
Expected volatility -   The expected volatility represents the extent to which our stock price is expected to fluctuate between the grant date and the expected term of the award. We use the historical volatility of our common stock for a period equal to the expected term of the option prior to the date of grant. We believe that historical volatility produces an estimate that is representative of our expectations about the future volatility of our common stock over the expected term.
 ·
Risk-free rate -   The risk-free rate is the implied yield available on US Treasury securities with a remaining term equal to the expected term of the option. We base our risk-free rate on a weighting of five and seven year US Treasury securities as of the date of grant to arrive at an approximated 5.5-year risk free rate of return.
 ·
Dividend yield -   The dividend yield represents the value of our stock’s annualized dividend as compared to our stock’s average price for the three-year period ended prior to the date of grant. It is calculated by dividing one full year of our expected dividends by our average stock price over the three-year period ended prior to the date of grant.

The assumptions used in valuing stock options were as follows:
89

The assumptions used in valuing stock options were as follows:
  Year Ended December 31, 
  2008  2007  2006 
  (weighted averages) 
Expected term (in years)  5.5   5.5   5.5 
Expected volatility  27.7%  29.6%  31.8%
Risk-free rate  2.9%  4.7%  4.7%
Expected dividend yield  1.0%  0.6%  0.8%
  Year Ended December 31, 
  2009  2008  2007 
(weighted averages)         
Expected Term (in Years)  5.5   5.5   5.5 
Expected Volatility  43.0%  27.7%  29.6%
Risk-Free Rate  2.0%  2.9%  4.7%
Expected Dividend Yield  1.2%  1.0%  0.6%
 
Stock option activity was as follows:
 
  Options  Weighted Average Exercise Price  Weighted Average Remaining Contractual Term  Aggregate Intrinsic Value 
     (per share)  (in years)  (in millions) 
Outstanding at December 31, 2008  6,082,375  $41.41       
Granted  1,574,252   50.99       
Exercised  (704,209)  25.01       
Forfeited  (132,127)  56.90       
Outstanding at December 31, 2009  6,820,291  $45.01   6.0  $182 
Exercisable at December 31, 2009  4,245,616  $37.62   4.4  $144 

102
Noble Energy, Inc.
Notes to Consolidated Financial Statements

        Weighted    
     Weighted  Average    
     Average  Remaining  Aggregate 
     Exercise  Contractual  Intrinsic 
  Options  Price  Term  Value 
     (per share)  (in years)  (in millions) 
Outstanding at December 31, 2007  6,175,061  $32.98       
Granted  1,139,758   73.14       
Exercised  (1,080,116)  24.31       
Forfeited  (152,328)  61.22       
Outstanding at December 31, 2008  6,082,375  $41.41  5.6 $                 80 
Exercisable at December 31, 2008  3,927,682  $29.80  3.9 $                 79 

The weighted-average grant-date fair value of options granted was $19.14 in 2009, $20.40 in 2008, and $18.77 in 2007, and $16.09 in 2006.2007. The total intrinsic value of options exercised was $19 million in 2009, $67 million in 2008, and $68 million in 2007, and $118 million in 2006.2007.
 
As of December 31, 2008, $242009, $29 million of compensation cost related to unvested stock options granted under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.31.4 years. We issue new shares of our common stock to settle option exercises. Dividends are not paid on unexercised options.
 
Restricted Stock Awards—Restricted stock activity was as follows:
 
 Shares  Weighted  Shares  Weighted  Shares Subject to Service Conditions  Weighted Average Grant Date Fair Value  Shares Subject to Market Conditions  Weighted Average Grant Date Fair Value 
 Subject to  Average  Subject to  Average     (per share)     (per share) 
 Service  Grant Date  Market  Grant Date 
 Conditions  Fair Value  Conditions  Fair Value 
    (per share)     (per share) 
Outstanding at December 31, 2007  567,590  $52.33   124,137  $33.11 
Granted  462,917   73.92   -   - 
Outstanding at December 31, 2008  891,027  $62.91   68,493  $35.40 
Awarded  612,226   51.63   -   - 
Vested  (80,347)  52.46   (54,199)  29.87   (19,245)  64.47   (68,493)  35.40 
Forfeited  (59,133)  61.78   (1,445)  45.94   (62,808)  58.18   -   - 
Outstanding at December 31, 2008  891,027  $62.91   68,493  $35.40 
Outstanding at December 31, 2009  1,421,200  $58.31   -  $- 
 
The total fair value of restricted stock that vested was $4 million in 2009, $10 million in 2008, and $6 million in 2007, and $2 million in 2006.2007.
 
Awards of time-vested restricted stock (shares subject to service conditions) were valued at the price of our common stock at the date of award.
 
In 2006, we awarded restricted stock with market-based vesting criteria. The fair value of the market-based restricted stock awards was estimated on the date of award using a Monte Carlo valuation model that used the assumptions in the following table.an expected volatility assumption of 28.4% and a risk free rate assumption of 4.4%. The Monte Carlo model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The number of simulations used was 100,000. Expected volatility represents the extent to which our stock price is expected to fluctuate between the award date and the award’s anticipated term. We used the historical volatility of our common stock for the three-year period ended prior to the date of award. The risk-free rate was based on a three-year period from US Treasury securities as of the year ended prior to the date of award.

The assumptions used  These awards vested in valuing the market-based restricted stock awards were as follows:

Year Ended
December 31,
2006
Number of simulations100,000
Expected volatility28.4%
Risk-free rate4.4%
2009.
 
As of December 31, 2008, $302009, $33 million of compensation cost related to all of our unvested restricted stock awarded under the Plans remained to be recognized. The cost is expected to be recognized over a weighted-average period of 1.81.4 years. Common stock dividends accrue on restricted stock grants and are paid upon vesting. We issue new shares of our common stock when awarding restricted stock.
 
Note 14 –14.  Earnings Per Share
 
Basic earnings per share of our common stock is computed using the weighted average number of shares of common stock outstanding during each period. The diluted earnings per share of our common stock may include the effect of Noble Energyour shares held in a rabbi trust, outstanding stock options or shares of restricted stock, except in periods in which there is a net loss. The following table summarizes the calculation of basic and diluted earnings per share:
 
  Year Ended December 31, 
  2009  2008  2007 
(millions, except per share amounts)         
Net Income (Loss) $(131) $1,350  $944 
Earnings Adjustment from Assumed Conversion of Dilutive Shares of Common Stock in Rabbi Trust (1)
  -   (20)  - 
Net Income (Loss) Used for Diluted Earnings Per Share Calculation $(131) $1,330  $944 
             
Weighted Average Number of Shares Outstanding, Basic  173   173   171 
Incremental Shares from Assumed Conversion of            
Dilutive Options, Restricted Stock and Shares of Common Stock in Rabbi Trust  -   3   2 
Weighted Average Number of Shares Outstanding, Diluted  173   176   173 
Earnings (Loss) Per Share, Basic $(0.75) $7.83  $5.52 
Earnings (Loss) Per Share, Diluted  (0.75)  7.58   5.45 

103
Noble Energy, Inc.
Notes to Consolidated Financial Statements

  Year Ended December 31, 
  2008  2007  2006 
  Income  Shares  Income  Shares  Income Shares 
  (in millions, except share and per share amounts) 
Net income $1,350   173  $944   171  $678  176 
Basic Earnings per Share $7.83      $5.52      $3.86    
                        
Net income $1,350   173  $944   171  $678  176 
Effect of dilutive stock options and restricted stock awards  -   2   -   2   -  3 
Effect of shares of Noble Energy common stock held in rabbi trust  (20)  1   -   -   -  - 
Net income available to common shareholders $1,330   176  $944   173  $678  179 
Diluted Earnings per Share (1)
 $7.58      $5.45      $3.79    
 
(1)The diluted earnings per share calculation for 2008 includes a decrease to net income of $20 million (net of tax) related to a deferred compensation gain from Noble Energy shares of our common stock held in a rabbi trust. When dilutive, the deferred compensation gain or loss (net of tax) is excluded from net income while the Noble Energy shares of our common stock held in the rabbi trust are included in the outstanding diluted share count.
 

The effect of stock options and unvested shares of restricted stock outstanding has not been included in the calculation of weighted average shares outstanding for diluted earnings per share for the year ended December 31, 2009 as their effect would have been antidilutive. Had we recognized net income for this period, incremental shares attributable to the assumed exercise of outstanding options and shares of restricted stock would have increased diluted weighted average shares outstanding by 2 million shares for the year ended December 31, 2009.

Options,3.7 million, 1.2 million, and 2.1 million weighted average stock options, shares of restricted stock and shares of our common stock held in a rabbi trust were antidilutive for the years ended December 31, 2009, 2008 and 2007, respectively, and were excluded from the EPS calculation above as theyof diluted earnings per share.  The weighted average exercise prices of the antidilutive stock options were antidilutive are as follows:$60.40 per share, $67.64 per share, and $52.41 per share for the years ended December 31, 2009, 2008 and 2007, respectively.
 
  
Weighted Outstanding Awards and Shares
 Weighted Average Exercise Price
  (in millions, except per share amounts) 
Year Ended December 31, 2008      
Stock options                1 $67.64 
Total excluded from diluted EPS calculation                1    
Year Ended December 31, 2007      
Stock options                1 $52.41 
Noble Energy common stock held in rabbi trust and shares of restricted stock                1    
Total excluded from diluted EPS calculation                2    
Year Ended December 31, 2006      
Stock options                1 $45.19 
Noble Energy common stock held in rabbi trust and shares of restricted stock                1    
Total excluded from diluted EPS calculation                2    
Note 15 –15.  Segment Information
 
We have operations throughout the world and manage our operations by country. The following information is grouped into five components that are all primarily in the business of crude oil and natural gas exploration, development, and production:acquisition: the United States; West Africa;Africa (Equatorial Guinea and Cameroon); Eastern Mediterranean (Israel and Cyprus); the North Sea; Israel;Sea (UK and the Netherlands); and Other International, Corporate and Marketing. Other International includes China, Ecuador and Argentina (through February 2008), China, Ecuador operations and Suriname.the gain on sale of Argentina (in 2009).
 
Accounting policies for geographical segments are the same as those described in the summary of significant accounting policies. Transfers between segments are accounted for at market value. We do not consider interest income and expense or income tax benefit or expense in our evaluation of the performance of geographical segments.
 

92104
Noble Energy, Inc.
Notes to Consolidated Financial Statements


            Other Int'l, 
    United West North   Corporate & 
  Total States Africa Sea Israel Marketing 
  (in millions) 
Year Ended December 31, 2008             
Revenues from third parties $4,058 $2,315 $541 $410 $157 $635 
Amount reclassified from AOCL (1)
  (331) (290) (41) -  -  - 
Intersegment revenue  -  434  -  -  -  (434)
Income from equity method investees  174  -  174  -  -  - 
Total Revenues  3,901  2,459  674  410  157  201 
                    
DD&A  791  646  34  55  24  32 
Loss on involuntary conversion of assets  9  9  -  -  -  - 
Impairment of assets  294  224  -  -  -  70 
Gain on derivative instruments  (440) (363) (77) -  -  - 
Income (loss) before income taxes  2,061  1,333  689  284  122  (367)
                    
Equity method investments  311  -  311  -  -  - 
Additions to long-lived assets  2,179  1,842  143  94  39  61 
Total assets at December 31, 2008 (2)
  12,384  9,212  1,614  775  366  417 
Year Ended December 31, 2007                   
Revenues from third parties $3,115 $1,651 $418 $364 $113 $569 
Amount reclassified from AOCL (1)
  (54) (42) (12) -  -  - 
Intersegment revenue  -  343  -  -  -  (343)
Income from equity method investees  211  -  211  -  -  - 
Total Revenues  3,272  1,952  617  364  113  226 
                    
DD&A  736  580  25  81  18  32 
Loss on involuntary conversion of assets  51  51  -  -  -  - 
Impairment of assets  4  4  -  -  -  - 
Gain on derivative instruments  (2) (2) -  -  -  - 
Income (loss) before income taxes  1,368  810  517  221  86  (266)
                    
Equity method investments  357  -  357  -  -  - 
Additions to long-lived assets  1,623  1,285  151  83  26  78 
Total assets at December 31, 2007 (2)
  10,831  7,918  1,355  562  268  728 
Year Ended December 31, 2006                   
Revenues from third parties $3,033 $1,743 $414 $115 $92 $669 
Amount reclassified from AOCL (1)
  (232) (232) -  -  -  - 
Intersegment revenue  -  426  -  -  -  (426)
Income from equity method investees  139  -  139  -  -  - 
Total Revenues  2,940  1,937  553  115  92  243 
                    
DD&A  633  552  24  9  14  34 
Impairment of assets  9  9  -  -  -  - 
Loss on derivative instruments  392  392  -  -  -  - 
Income (loss) before income taxes  1,096  631  494  73  71  (173)
                    
Equity method investments  373  -  373  -  -  - 
Additions to long-lived assets  1,895  1,456  46  336  15  42 
Total assets at December 31, 2006 (2)
  9,589  7,225  961  343  257  803 
  Consolidated United States West Africa Eastern Mediter-ranean North Sea Other Int'l, Corporate, Marketing 
(millions)             
Year Ended December 31, 2009             
Revenues from Third Parties $2,287 $1,323 $340 $144 $153 $327 
Reclassification from AOCL (1)
  (58) (29) (29) -  -  - 
Intersegment Revenue  -  161  -  -  -  (161)
Income from Equity Method Investees  84  -  84  -  -  - 
Total Revenues (2)
  2,313  1,455  395  144  153  166 
DD&A  816  689  38  20  34  35 
Asset Impairments  604  504  -  -  -  100 
Loss on Commodity Derivative Instruments  110  73  37  -  -  - 
Income (Loss) Before Income Taxes  (264) (287) 257  98  62  (394)
Equity Method Investments $303 $-  303 $- $- $- 
Additions to Long-Lived Assets  1,282  911  124  103  103  41 
Total Assets at December 31, 2009 (3)
  11,807  8,669  1,731  486  635  286 
Year Ended December 31, 2008                   
Revenues from Third Parties $4,058 $2,315 $541 $157 $410 $635 
Reclassification from AOCL (1)
  (331) (290) (41) -  -  - 
Intersegment Revenue  -  434  -  -  -  (434)
Income from Equity Method Investees  174  -  174  -  -  - 
Total Revenues (2)
  3,901  2,459  674  157  410  201 
DD&A  791  646  34  24  55  32 
Asset Impairments  294  224  -  -  -  70 
Gain on Commodity Derivative Instruments  (440) (363) (77) -  -  - 
Income (Loss) Before Income Taxes  2,061  1,333  689  122  284  (367)
Equity Method Investments $311 $- $311 $- $- $- 
Additions to Long-Lived Assets  2,179  1,842  143  39  94  61 
Total Assets at December 31, 2008 (3)
  12,384  9,212  1,614  366  775  417 
Year Ended December 31, 2007                   
Revenues from Third Parties $3,115 $1,651 $418 $113 $364 $569 
Reclassification from AOCL (1)
  (54) (42) (12) -  -  - 
Intersegment Revenue  -  343  -  -  -  (343)
Income from Equity Method Investees  211  -  211  -  -  - 
Total Revenues (2)
  3,272  1,952  617  113  364  226 
DD&A  736  580  25  18  81  32 
Loss on Involuntary Conversion of Assets  51  51  -  -  -  - 
Income (Loss) Before Income Taxes  1,368  810  517  86  221  (266)
Equity Method Investments $357 $- $357 $- $- $- 
Additions to Long-Lived Assets  1,623  1,285  151  26  83  78 
Total Assets at December 31, 2007 (3)
  10,831  7,918  1,355  268  562  728 
 
(1)Revenues include decreases resulting from hedging activities. The decreases resulted from hedge gains and losses that were deferred in AOCL, as a result of previous cash flow hedge accounting, and subsequently reclassified to revenues.
(2)Revenues from third parties for all foreign countries, in total, were $791 million in 2009, $1.3 billion in 2008, and $1.1 billion 2007.
(3)
The US reporting unit includes goodwill of $758 million at December 31, 2009, $759 million at December 31, 2008, and $761 million at December 31, 2007,2007. Long-lived assets located in all foreign countries, in total, were $1.6 billion, $1.5 billion, and $781 million$1.4 billion at December 31, 2006.2009, 2008, and 2007, respectively.

93105
Noble Energy, Inc.
Notes to Consolidated Financial Statements


Note 16 –16.  Additional Shareholders’ Equity Information
Activity in shares of our common stock and treasury stock was as follows:
  Year Ended December 31, 
  2009  2008 
Common Stock Shares Issued      
Shares, Beginning of Period  192,296,764   190,814,309 
Exercise of Common Stock Options  704,209   1,080,116 
Restricted Stock Awards, Net of Forfeitures  549,418   402,339 
Shares, End of Period  193,550,391   192,296,764 
Treasury Stock        
Shares, Beginning of Period  18,563,409   18,580,865 
Shares Received From Employees in Payment of Withholding Taxes Due on Vesting of Shares of Restricted Stock  20,784   32,544 
Rabbi Trust Shares Sold  (1,892)  (50,000)
Shares, End of Period  18,582,301   18,563,409 
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
   Accumulated Other Comprehensive Loss 
   Oil and Gas Cash Flow Hedges  Pension-Related and Other  Total 
(millions)           
December 31, 2006           
Cash Flow Hedges $(104) $(36)$(140) 
  Realized Amounts Reclassified Into Earnings                 33                     3                 36 
  Unrealized Change in Fair Value              (184)                   (1)             (185) 
Net Change in Other                     -                     5                    5 
December 31, 2007             (255)                (29)            (284) 
Cash Flow Hedges           
  Realized Amounts Reclassified Into Earnings               207                     3                210 
  Unrealized Change in Fair Value                     -                   (4)                 (4) 
Net Change in Other                     -                (32)              (32) 
December 31, 2008               (48)                (62)              (110) 
Cash Flow Hedges           
  Realized Amounts Reclassified Into Earnings                 36                     3                 39 
Net Change in Other                     -                   (4)                 (4) 
December 31, 2009 $  (12)  $(63)$(75) 
All amounts in the table above are reported net of tax. The effective income tax rate applied to AOCL was 37.6% for the period December 31, 2006 - 2008, and 35.0% at December 31, 2009.
 
Activity in shares of our common stock and treasury stock was as follows:
  Year Ended December 31, 
  2008  2007 
Common stock shares issued      
Shares, beginning of period  190,814,309   188,808,087 
Exercise of common stock options  1,080,116   1,479,040 
Restricted stock awards, net of forfeitures  402,339   527,182 
Shares, end of period  192,296,764   190,814,309 
Treasury stock        
Shares, beginning of period  18,580,865   16,574,384 
Shares received from employees in payment of withholding taxes due on vesting of shares of restricted stock
  32,544   - 
Shares purchased pursuant to share buyback program  -   2,006,481 
Shares, end of period  18,613,409   18,580,865 
During 2007, we completed a $500 million common stock repurchase program begun in 2006.
Accumulated other comprehensive loss in the shareholders’ equity section of the balance sheet included:
  Accumulated Other Comprehensive Loss 
  Oil and Gas Cash Flow Hedges  Pension-Related and Other  Total 
  (in millions) 
December 31, 2005 $(764) $(20) $(784)
Cash flow hedges            
  Realized amounts reclassified into earnings  145   1   146 
  Unrealized change in fair value  250   -   250 
  Unrealized amounts reclassified into earnings  265   -   265 
Net change in minimum pension liability and other  -   16   16 
Adoption of SFAS 158  -   (33)  (33)
December 31, 2006  (104)  (36)  (140)
Cash flow hedges            
  Realized amounts reclassified into earnings  33   3   36 
  Unrealized change in fair value  (184)  (1)  (185)
Net change in  other  -   5   5 
December 31, 2007  (255)  (29)  (284)
Cash flow hedges            
  Realized amounts reclassified into earnings  207   3   210 
  Unrealized change in fair value  -   (4)  (4)
Net change in  other  -   (32)  (32)
December 31, 2008 $(48) $(62) $(110)
All amounts in the table above are reported net of tax. The effective income tax rate applied to AOCL increased from 35% at December 31, 2005 to 37.6% at December 31, 2006 and remained 37.6% at December 31, 2007 and 2008.
Note 17 –17.  Commitments and Contingencies
 
Purchaser Bankruptcy   – We havehad an exposure from crude oil sales for the months of June and July 2008 to SemCrude, L.P. (SemCrude), a subsidiary of SemGroup, L.P. (SemGroup).  On July 22, 2008, SemGroup, including SemCrude, filed a voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code under Case Number 08-11525 (BLS) in the United States Bankruptcy Court for the District of Delaware.
As of December 31, During 2008, we had adetermined that the carrying value of our receivable of approximately $71 million from SemCrude. We have determined that it is probable thatshould be reduced by $38 million. Based upon the confirmation of SemCrude's plan for reorganization on October 26, 2009, and further based upon a portion of the receivable is uncollectible. Therefore, during third quarter 2008,settlement reached with SemCrude on October 27, 2009, we further reduced the carrying value of theour receivable by $12 million. We have received distributions of approximately $12 million from SemCrude receivable and recognized a pre-tax charge of $38 million forbelieve the probable loss.


We are pursuing various legal remedies to protect our interests. We believe that ultimate disposition of this matter will not have a material adverse affect on our financial position, results of operations, or cash flows.to be finally determined.
 
Legal Proceedings   – We are among a group of 18 defendants named in a lawsuit filed August 23, 2002 by Dore Energy Corporation under Docket Number 10-16202 in the 38th Judicial District Court, Cameron Parish, Louisiana.  The lawsuit alleges damage to property owned by Dore resulting from oil and gas activities dating to the 1930’s.  Our predecessor, Samedan Oil Corporation, operated on a portion of the property from 1989 to 1999.  Dore has delivered documents alleging approximately $140 million in damages.  Trial is currently set for April 27, 2009.  We intend to vigorously defend against these allegations and believe that our share of damages, if any, will not have a material adverse effect on our financial position, results of operations, or cash flows.
We are involved in various other legal proceedings in the ordinary course of business.  These proceedings are subject to the uncertainties inherent in any litigation.  We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows.
 
Non-Cancelable Leases and Other Commitments—Commitments   We hold leases and other commitments for drilling rigs, buildings, equipment and other properties.property. Rental expense for office buildings and oil and gas operations equipment was approximately $22 million in 2009, $20 million in 2008, and $13 million in 2007, and $12 million in 2006.
Minimum commitments as of December 31, 2008 consist of the following:
  Drilling, Equipment, and Purchase Obligations Throughput Agreement  Transportation and Gathering  Operating Lease Obligations  Total 
  (in millions) 
2009$        485 $14 $     12 $           12 $      523 
2010           439        19          9               10         477
 
2011           399        19          8                 8         434 
2012             72        19          5                 7         103 
2013               -        19          5                 1           25 
2014 and thereafter               -          5          4               18           27 
Total$   1,395 $95 $     43 $           56 $  1,589 
Note 18 – Recently Issued Pronouncements
SFAS 141(R) and SFAS 160 – In 2007, the FASB issued SFAS No. 141(R), “Business Combinations” (SFAS 141(R)) and SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements” (SFAS 160). These statements require most identifiable assets, liabilities and noncontrolling interests to be recorded at full fair value and require noncontrolling interests to be reported as a component of equity. Both statements are effective for periods beginning on or after December 15, 2008. SFAS 141(R) will be applied to business combinations occurring after the effective date and SFAS 160 will be applied prospectively to all noncontrolling interests, including any that arose before the effective date. We adopted SFAS 141(R) and SFAS 160 as of January 1, 2009. There were no non-controlling interests at adoption date. Adoption had no effect on our financial position and results of operations.
Adoption of SFAS 159—In 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities” (SFAS 159). SFAS 159 provides companies with an option to report selected financial assets and liabilities at fair value. SFAS 159 was effective as of the beginning of an entity’s first fiscal year beginning after November 15, 2007. We adopted SFAS 159 as of January 1, 2008. Adoption had no effect on our financial position or results of operations as we made no elections to report selected financial assets or liabilities at fair value.
SFAS 161 – In March 2008, the FASB issued SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities” (SFAS 161). SFAS 161 amends and expands the disclosure requirements of SFAS 133 and requires qualitative disclosures about objectives and strategies for using derivative instruments, quantitative disclosures about fair value amounts of derivative instruments and related gains and losses, and disclosures about credit-risk-related contingent features in derivative agreements. SFAS 161 is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008. We adopted SFAS 161 as of January 1, 2009. The statement provides only for enhanced disclosures. Therefore, adoption had no impact on our financial position or results of operations.
 
 

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Notes to Consolidated Financial Statements

FSP FAS 132(R) –    In December 2008, the FASB issued FSP FAS 132(R), “Employers’ Disclosures About Postretirement Benefit Plan Assets” (FSP FAS 132(R)). FSP FAS 132(R) requires employers to make additional disclosures about plan assets for defined benefit pension and other postretirement benefit plans beginning with annual periods ending after December 15, 2009. The requirements apply to entities that are subject to the disclosure requirements of FAS 132R. Disclosures are to provide an understanding of how investment allocation decisions are made, the major categories of plan assets, the inputs and valuation techniques used to measure the fair value of plan assets, the effect of fair-value measurements using significant unobservable inputs on changes in plan assets for the period, and significant concentrations of risk within plan assets. We adopted FSP FAS 132(R) as of January 1, 2009. The statement provides only for enhanced disclosures. Therefore, adoption had no impact on our financial position or results of operations.
 
EITF 08-06– In November 2008, the FASB ratified the consensus reached in EITF 08-06, “Equity Method Investment Accounting Considerations” (EITF 08-06). EITF 08-06 was issued to address questions that arose regarding the applicationMinimum commitments as of December 31, 2009 consist of the equity method subsequent to the issuance of FAS 141(R). EITF 08-06 concluded that equity method investments should continue to be recognized using a cost accumulation model, thus continuing to include transaction costs in the carrying amount of the equity method investment. In addition, EITF 08-06 clarifies that an impairment assessment should be applied to the equity method investment as a whole, rather than to the individual assets underlying the investment. EITF 08-06 is effective for fiscal years beginning on or after December 15, 2008. We adopted EITF 08-06 as of January 1, 2009. Adoption had no effect on our financial position and results of operations.following:
   Drilling, Equipment, and Purchase Obligations Throughput Agreement  Transportation and Gathering  Operating Lease Obligations  
FPSO Lease Obligation (1)
  Total 
(millions)                   
2010 $671 $19 $11 $12 $ - $713 
2011               336          19         10                  10                    -               375 
2012                 27          19           7                    9                   35               97 
2013                  -          19           6                  10                   69               104 
2014                  -            5           3                  11                   69                 88 
2015 and Thereafter                  -           -           3                  31                 295               329 
 Total $1,034 $81 $40 $83 $468 $1,706 
(1)Annual lease payments, net to our interest, exclude regular maintenance and operational costs, and will begin when the FPSO initiates producing operations. These payments are also subject to change based on change orders implemented during the construction period, final accounting treatment and other factors. See Note 8. Debt.


 

Noble Energy, Inc.

Supplemental Oil and Gas Information (Unaudited)
(Unaudited)


In accordance with SFAS No. 69, “DisclosuresUS GAAP for disclosures about Oiloil and Gas Producing Activities” (SFAS 69),gas producing activities, and regulations of the SEC rules for oil and gas reporting disclosures, we are making the following supplemental disclosures about our crude oil and natural gas reserves and exploration and production operations.activities.
Reserves
 
There are numerous uncertainties inherent in estimating quantities of proved crude oil and natural gas reserves. Crude oil and natural gas reserve engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot be precisely measured. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment.
Engineers in our Houston, Denver and London offices prepare all reserve estimates for our different geographical regions. These reserve estimates are reviewed and approved by senior engineering staff and division management with final approval by the vice president in charge of corporate reserves and certain members of senior management. During each of the years 2008, 2007 and 2006, we retained Netherland, Sewell & Associates, Inc. (NSAI), independent third-party reserve engineers, to perform reserve audits of proved reserves. The reserve audit for 2008 included a detailed review of 18 of our major international, deepwater Gulf of Mexico and US onshore fields, which covered approximately 79% of US proved reserves and 97% of international proved reserves (86% of total proved reserves). The reserve audit for 2007 included a detailed review of 16 of our major international, deepwater Gulf of Mexico and US onshore fields, which covered approximately 71% of US proved reserves and 96% of international proved reserves (81% of total proved reserves). The reserve audit for 2006 included a detailed review of 14 of our major international, deepwater Gulf of Mexico and US onshore fields, which covered approximately 80% of our total proved reserves. See Items 1 and 2. Business and Properties—Proved Reserves.
Results of drilling, testing and production subsequent to the date of the estimate may justify revision of such estimate. Accordingly, reservereserves estimates are often different from the quantities of crude oil and natural gas that are ultimately recovered.
 
Recent SEC and FASB Rule-Making Activity   In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserves reporting requirements. See Note 2. Summary of Significant Accounting Policies – Recently Adopted Standards. We adopted the rules effective December 31, 2009 and the rule changes, including those related to pricing and technology, are included in our reserves estimates.
In addition, in January 2010 the FASB issued Accounting Standards Update 2010-03, "Oil and Gas Reserve Estimation and Disclosures", to provide consistency with the SEC rules. See Note 2. Summary of Significant Accounting Policies – Recently Adopted Standards.
Application of the new rules resulted in the use of lower prices at December 31, 2009 for both oil and gas than would have resulted under the previous rules. Use of 12-month average pricing at December 31, 2009 as required by the new rules resulted in a decrease in proved reserves of approximately 27 MMBoe. Use of year-end prices as required by the old rules would have resulted in an increase in proved reserves of approximately 34 MMBoe at December 31, 2009.  Therefore, the total impact of the new price methodology was negative reserves revisions of 61 MMBoe.  In addition, the new proved undeveloped reserves rules resulted in a reduction of proved reserves of approximately 18 MMBoe due to limiting proved undeveloped reserves locations to those scheduled to be drilled within the next five years. The majority of the reserves reclassified out of proved reserves were associated with the Wattenberg field, where we maintain an extensive multi-year development program.
Because we use quarter-end reserves and add back current period production to calculate quarterly DD&A, adoption of these new standards had an impact on fourth quarter 2009 DD&A expense. We estimate the impact of using 12-month average commodity prices, as required by the new standards, instead of year-end commodity prices, to be an increase in fourth quarter 2009 DD&A expense of approximately $16 million (or $0.06 per share).
Reserves Estimates Qualified petroleum engineers in our Houston, Denver and London offices prepare all reserves estimates for our different geographical regions. These reserves estimates are reviewed and approved by regional management and senior engineering staff with final approval by the Vice President - Strategic Planning, Environmental Analysis & Reserves and certain members of senior management. For additional information regarding our reserves estimation process and internal controls see Items 1. and 2. Business and Properties – Proved Reserves Disclosures –  Internal Controls Over Reserves Estimates and Technologies Used in Reserves Estimation.
Third-Party Reserves Audit   We retained Netherland, Sewell & Associates, Inc. (NSAI), independent, third-party reserves engineers, to perform a reserves audit of proved reserves as of December 31, 2009. The reserves audit included a detailed review of 20 of our major international, deepwater Gulf of Mexico and US onshore fields, which covered approximately 78% of US proved reserves and 96% of international proved reserves (86% of total proved reserves). For additional information regarding reserves audits for the years 2009, 2008, and 2007, see Items 1. and 2. Business and Properties – Proved Reserves Disclosures.
Geographic Areas   Our supplemental disclosures are grouped by geographic area and include the United States, West Africa (EquatorialEquatorial Guinea, Israel and Cameroon), Israel,Other International. Other International includes Ecuador, North Sea, and Other International (Argentina, China, and Suriname)Argentina (through February 2008). Operations in Equatorial Guinea, Cameroon, Ecuador, China, Cyprus and Suriname are conducted in accordance with the terms of production sharing contracts. Operations in Cameroon are conducted in accordance with the terms of a production sharing contract and a mining concession. Operations in other foreign locations are conducted in accordance with concession agreements or licenses.
 
Definitions   The following definitions apply to the terms used in the paragraphs above:
 
Reserve Estimate.Reserves Estimate   The determination of an estimate of a quantity of oil or gas reserves that are thought to exist at a certain date, considering existing prices and reservoir conditions.
 
Reserve Audit.Reserves Audit   The process involvingof reviewing certain of the pertinent facts interpreted and assumptions underlying a reserves estimate prepared by another party and the rendering of an independent third-party engineering firm’s visits, collectionopinion about the appropriateness of anythe methodologies employed, the adequacy and all required geologic, geophysical, engineeringquality of the data relied upon, the depth and economic data,thoroughness of the reserves estimation process, the classification of reserves appropriate to the relevant definitions used, and such firm’s complete external preparationthe reasonableness of reserve estimates.the estimated reserves quantities.
 
The following definitions apply to our categories of proved reserves:
 
Proved Reserves.Oil and Gas Reserves  Proved oil and gas reserves are the estimatedthose quantities of crude oil naturaland gas, and natural gas liquids which, geologicalby analysis of geoscience and engineering data, demonstratecan be estimated with reasonable certainty to be recoverable in future yearseconomically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and operating conditions (government i.e.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., prices

108
Noble Energy, Inc.
Supplemental Oil and costs as of the date the estimate is made). Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions.Gas Information
(Unaudited)


 
Proved Developed Reserves.Oil and Gas Reserves   Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
 
Proved Undeveloped Reserves.Oil and Gas Reserves  Proved undeveloped oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
 
For complete definitions of proved natural gas, natural gas liquids and crude oil reserves, refer to SEC Regulation S-X, Rule 4-10(a)(2)(6), (3)(22) and (4)(31).



 


Noble Energy, Inc.
Supplemental Oil and Gas Information (Unaudited)
Recent SEC Rule-Making Activity – In December 2008, the SEC announced that it had approved revisions designed to modernize the oil and gas company reserve reporting requirements. The most significant amendments to the requirements include the following:
·Commodity Prices - Economic producibility of reserves and discounted cash flows will be based on a 12-month average commodity price unless contractual arrangements designate the price to be used.
·Disclosure of Unproved Reserves - Probable and possible reserves may be disclosed separately on a voluntary basis.
·Proved Undeveloped Reserve Guidelines – Reserves may be classified as proved undeveloped if there is a high degree of confidence that the quantities will be recovered.
·Reserve Estimation Using New Technologies - Reserves may be estimated through the use of reliable technology in addition to flow tests and production history.
·Reserve Personnel and Estimation Process - Additional disclosure is required regarding the qualifications of the chief technical person who oversees our reserves estimation process.  We will also be required to provide a general discussion of our internal controls used to assure the objectivity of the reserves estimate.
·Disclosure by Geographic Area - Reserves in foreign countries or continents must be presented separately if they represent more than 15% of our total oil and gas proved reserves.
·
Non-Traditional Resources – The definition of oil and gas producing activities will expand and focus on the marketable product rather than the method of extraction.
The rules are effective for fiscal years ending on or after December 31, 2009, and early adoption is not permitted.  We are currently evaluating the new rules and assessing the impact they will have on our reported oil and gas reserves.  The SEC is coordinating with the Financial Accounting Standards Board to obtain the revisions necessary to SFAS 19, “Financial Accounting and Reporting by Oil and Gas Producing Companies”, and SFAS 69 to provide consistency with the new rules. In the event that consistency is not achieved in time for companies to comply with the new rules, the SEC will consider delaying the compliance date.
(Unaudited)



Proved Oil Reserves (Unaudited)
The following reservereserves schedule was developed by our reservereserves engineers and sets forth the changes in estimated quantities of proved crude oil reserves:reserves:
 
  Crude Oil, Condensate and NGLs (MMBbls) 
  United  West  North  Other    
  States  Africa  Sea  
Int'l (1)
  Total 
Proved reserves as of:               
December 31, 2005  152   101   20   18   291 
Revisions of previous estimates  -   (2)  -   -   (2)
Extensions, discoveries and other additions (2)
  23   -   -   2   25 
Purchase of minerals in place (3)
  19   -   -   -   19 
Sale of minerals in place (4)
  (7)  -   -   -   (7)
Production (5)
  (17)  (9)  (1)  (3)  (30)
December 31, 2006  170   90   19   17   296 
Revisions of previous estimates (6)
  28   -   1   -   29 
Extensions, discoveries and other additions (7)
  27   -   10   -   37 
Purchase of minerals in place  -   -   -   -   - 
Sale of minerals in place  (2)  -   -   -   (2)
Production (5)
  (16)  (8)  (5)  (2)  (31)
December 31, 2007  207   82   25   15   329 
Revisions of previous estimates (8)
  (10)  1   -   -   (9)
Extensions, discoveries and other additions (9)
  16   -   2   9   27 
Purchase of minerals in place  3   -   -   -   3 
Sale of minerals in place (10)
  -   -   -   (7)  (7)
Production (5)
  (18)  (8)  (4)  (2)  (32)
December 31, 2008  198   75   23   15   311 
                     
Proved developed reserves as of:                    
December 31, 2005  114   101   8   16   239 
December 31, 2006  115   90   19   16   240 
December 31, 2007  129   71   15   14   229 
December 31, 2008  121   57   15   6   199 
  Crude Oil, Condensate and NGLs (MMBbls) 
  United States  Equatorial Guinea  
Other Int'l (1)
  Total 
Proved Reserves as of:            
December 31, 2006  170   90   36   296 
Revisions of Previous Estimates (2)
  28   -   1   29 
Extensions, Discoveries and Other Additions (3)
  27   -   10   37 
Purchase of Minerals in Place  -   -   -   - 
Sale of Minerals in Place  (2)  -   -   (2)
Production (4)
  (16)  (8)  (7)  (31)
December 31, 2007  207   82   40   329 
Revisions of Previous Estimates (2)
  (10)  1   -   (9)
Extensions, Discoveries and Other Additions (3)
  16   -   11   27 
Purchase of Minerals in Place  3   -   -   3 
Sale of Minerals in Place (5)
  -   -   (7)  (7)
Production (4)
  (18)  (8)  (6)  (32)
December 31, 2008  198   75   38   311 
Revisions of Previous Estimates (2)
  (5)  (1)  -   (6)
Extensions, Discoveries and Other Additions (3)
  32   26   1   59 
Purchase of Minerals in Place  1   -   -   1 
Sale of Minerals in Place  -   -   -   - 
Production (4)
  (17)  (8)  (4)  (29)
December 31, 2009  209   92   35   336 
                 
Proved Developed Reserves as of:                
December 31, 2006  115   90   35   240 
December 31, 2007  129   71   29   229 
December 31, 2008  121   57   21   199 
December 31, 2009  122   49   23   194 
                 
Proved Undeveloped Reserves as of:                
December 31, 2006  55   -   1   56 
December 31, 2007  78   11   11   100 
December 31, 2008  77   18   17   112 
December 31, 2009  87   43   12   142 
 
(1)Other International includes the North Sea, China and Argentina. We sold our Argentina assets in Argentina inFebruary 2008.
(2)
The increase in US proved reserves includes 14 MMBbl in the US Wattenberg field, primarily due to infill drilling activities.
(3)
Purchase of minerals in place includes 18 MMBbl acquired in the purchase of U.S. Exploration. See Note 4—Acquisitions and Divestitures.
(4)
Sale of minerals in place is primarily due to the sale of Gulf of Mexico shelf properties. See Note 4—Acquisitions and Divestitures.
(5)West Africa production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2008, 3 MMBbl in 2007 and 3 MMBbl in 2006.
(6)The positive revisions within the US are primarily due to 29 MMBbl of NGLs, previously recorded in proved natural gas reserves, being reflected in proved oil reserves, partially offset by negative revisions within the US Southern region related to less than expected well performance. The 2008 negative revisions within the US are primarily due to lower year-end prices (28 MMBbl), partially offset by the recording of NGLs which had previously been recorded in proved natural gas reserves. The 2009 negative revisions within the US are primarily due to performance revisions, the majority of which related to the abandonment of Main Pass (10 MMBbl) and reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s new five year development rule (5 MMBbl), partially offset by higher year-end prices (10 MMBbl).
(7)(3)
The 2007 increase in proved reserves includes 17 MMBbl in the US Wattenberg field, primarily due to infill drilling activities, 8 MMBbl in the deepwater Gulf of Mexico and 10 MMBbl in the North Sea Dumbarton field area.
(8)The negative revisions within the US are primarily due to lower year-end prices (28 MMBbl), partially offset by the recording of NGLs which had previously been recorded in proved natural gas reserves.
(9)The2008 increase in proved reserves includes 13 MMBbl in the US Wattenberg field, primarily due to infill drilling activities, and 9 MMBbl in China. The 2009 increase in proved reserves includes 20 MMBbl related to the ongoing development of the US Wattenberg field, 11 MMBbl in the deepwater Gulf of Mexico for the Santa Cruz, Isabela and Swordfish fields, and 26 MMBbl in Equatorial Guinea for the Aseng field. 
(10)(4)Equatorial Guinea production includes sales from the Alba field to the Alba LPG plant of 3 MMBbl in 2009, 3 MMBbl in 2008, and 3 MMBbl in 2007.
Decrease
(5)The decrease is due to sale of our assets in Argentina. Argentina assets. See Note 4 –4. Acquisitions and Divestitures.
 

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Supplemental Oil and Gas Information
(Unaudited)


Proved Gas Reserves (Unaudited)
Proved Gas Reserves (Unaudited)The following reservereserves schedule was developed by our reservereserves engineers and sets forth the changes in estimated quantities of proved natural gas reserves:
 
     Natural Gas and Casinghead Gas (Bcf) 
  United  West        Other    
  States  Africa  Israel  Ecuador  
Int'l (1)
  Total 
Proved reserves as of:                  
December 31, 2005  1,641   901   394   144   11   3,091 
Revisions of previous estimates (2)
  (83)  58   -   33   11   19 
Extensions, discoveries and other additions (3)
  314   -   -   -   -   314 
Purchase of minerals in place (4)
  141   3   -   -   -   144 
Sale of minerals in place (5)
  (110)  -   -   -   -   (110)
Production  (164)  (17)  (34)  (9)  (3)  (227)
December 31, 2006  1,739   945   360   168   19   3,231 
Revisions of previous estimates (6)
  (67)  44   -   29   (1)  5 
Extensions, discoveries and other additions (7)
  316   -   -   -   3   319 
Purchase of minerals in place  3   -   -   -   -   3 
Sale of minerals in place  -   -   -   -   -   - 
Production  (151)  (48)  (41)  (9)  (2)  (251)
December 31, 2007  1,840   941   319   188   19   3,307 
Revisions of previous estimates (8)
  (253)  34   1   -   8   (210)
Extensions, discoveries and other additions (9)
  345   78   4   -   -   427 
Purchase of minerals in place (10)
  72   -   -   -   -   72 
Sale of minerals in place  -   -   -   -   -   - 
Production  (145)  (75)  (51)  (8)  (2)  (281)
December 31, 2008  1,859   978   273   180   25   3,315 
                         
Proved developed reserves as of:                        
December 31, 2005  1,279   431   337   144   11   2,202 
December 31, 2006  1,255   360   303   168   19   2,105 
December 31, 2007  1,259   830   263   188   16   2,556 
December 31, 2008  1,268   700   216   180   21   2,385 
  Natural Gas and Casinghead Gas (Bcf)    
  United States  Equatorial Guinea  Israel  
Other Int'l (1)
  Total 
Proved Reserves as of:               
December 31, 2006  1,739   945   360   187   3,231 
Revisions of Previous Estimates (2)
  (67)  44   -   28   5 
Extensions, Discoveries and Other Additions (3)
  316   -   -   3   319 
Purchase of Minerals in Place  3   -   -   -   3 
Sale of Minerals in Place  -   -   -   -   - 
Production  (151)  (48)  (41)  (11)  (251)
December 31, 2007  1,840   941   319   207   3,307 
Revisions of Previous Estimates (2)
  (253)  34   1   8   (210)
Extensions, Discoveries and Other Additions (3)
  345   78   4   -   427 
Purchase of Minerals in Place (4)
  72   -   -   -   72 
Sale of Minerals in Place  -   -   -   -   - 
Production  (145)  (75)  (51)  (10)  (281)
December 31, 2008  1,859   978   273   205   3,315 
Revisions of Previous Estimates (2)
  (397)  49   (2)      (350)
Extensions, Discoveries and Other Additions (3)
  211   -   5   2   218 
Purchase of Minerals in Place  6   -   -   -   6 
Sale of Minerals in Place  -   -   -   -   - 
Production  (145)  (87)  (42)  (11)  (285)
December 31, 2009  1,534   940   234   196   2,904 
                     
Proved Developed Reserves as of:                    
December 31, 2006  1,255   360   303   187   2,105 
December 31, 2007  1,259   830   263   204   2,556 
December 31, 2008  1,268   700   216   201   2,385 
December 31, 2009  1,114   638   191   192   2,135 
                     
Proved Undeveloped Reserves as of:                    
December 31, 2006  484   585   57   -   1,126 
December 31, 2007  581   111   56   3   751 
December 31, 2008  591   278   57   4   930 
December 31, 2009  420   302   43   4   769 
(1)Other International includes the North Sea, ChinaEcuador and Argentina. We soldChina. See Note 3. Impairments for a discussion of impairment charges related to our assetsinvestment in Argentina in 2008.Ecuador.
(2)West Africa’s positive revisions are primarily due to additional production allowances related to LNG sales.
Positive revisions in Ecuador are related to better than expected well performance.
(3)The increase in US proved reserves includes 140 Bcf in the Wattenberg field, 77 Bcf in the Piceance basin and 55 Bcf in the Mid-continent area, primarily due to infill drilling activities.
(4)
Purchase of minerals in place includes 128 Bcf acquired in the purchase of U.S. Exploration. See Note 4—Acquisitions and Divestitures.
(5)
Sale of minerals in place is primarily due to sale of Gulf of Mexico shelf properties. See Note 4—Acquisitions and Divestitures.
(6)
The2007 negative revisions within the US are primarily due to 103 Bcf of natural gas being reflected in the proved oil reserves table as NGLs, partially offset by positive revisions resulting from an increase in commodity price. West Africa’sThe 2008 negative revisions in the US are primarily due to lower year-end prices (109 Bcf), as well as additional natural gas volumes being reflected in the proved oil reserves table as NGLs. The 2009 negative revisions in the US are primarily due to lower year-end prices (224 Bcf), reclassifications of proved undeveloped reserves to probable reserves as a result of the SEC’s new five year development rule (75 Bcf), and increased lease operating expense and various well performance issues (98 Bcf). Equatorial Guinea’s positive revisions in 2007, 2008 and 2009 are primarily due to additional production allowances related to LNG sales. PositiveThe 2007 positive revisions in Ecuador are related to better than expected well performance.
(7)(3)The 2007 increase in US proved reserves includes 142 Bcf in the Wattenberg field, 83 Bcf in the Piceance basin and 19 Bcf in the Niobrara trend, primarily due to infill drilling activities.
(8)
Negative revisions in the US are primarily due to lower year-end prices (109 Bcf), as well as additional natural gas volumes being reflected in the oil reserves table as NGLs. West Africa’s positive revisions are primarily due to additional production allowances related to LNG sales.
(9)The 2008 increase in US proved reserves includes 106 Bcf in the Wattenberg field and 173 Bcf in the Rockies,Rocky Mountain area, primarily fromin the Piceance basin and Niobrara trend, primarily due to infill drilling activities. The remaining increase is due to other development programs in the US Northern and Southern regions. The 2009 increase in US proved reserves is primarily due to ongoing low-risk development programs onshore in the Wattenberg field, the Rocky Mountain area, and East Texas.
 (10)(4)
Purchase of minerals in place is primarily due to the Mid-continent acquisition. acquisition. See Note 4—4. Acquisitions and Divestitures.


100111
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Results of Operations for Oil and Gas Producing Activities (Unaudited)
Results of Operations for Oil and Gas Producing Activities (Unaudited)   Aggregate results of operations in connection with crude oil and natural gas producing activities are as follows:
 
Aggregate results of operations in connection with crude oil and natural gas producing activities are as follows:
  United  West        North  Other    
  States  Africa  Israel  Ecuador  Sea  
Int'l (1)
  Total 
  (in millions) 
Year Ended December 31, 2008                     
Revenues                     
Sales (2)
 $2,459  $500  $157  $-  $410  $125  $3,651 
Sales to affiliated power plant  -   -   -   30   -   -   30 
Total Revenues  2,459   500   157   30   410   125   3,681 
Production costs (3)
  470   42   12   12   66   45   647 
Exploration expense  111   9   4   1   18   39   182 
DD&A  653   34   23   9   55   11   785 
Impairment of assets  224   -   -   -   -   -   224 
Income before income taxes  1,001   415   118   8   271   30   1,843 
Income tax expense  339   99   22   2   132   17   611 
Results of operations (4)
 $662  $316  $96  $6  $139  $13  $1,232 
Equity investee results of operations (5)
 $-  $118  $-  $-  $-  $-  $118 
Year Ended December 31, 2007                            
Revenues                            
Sales (2)
 $1,952  $406  $113  $-  $364  $131  $2,966 
Sales to affiliated power plant  -   -   -   35   -   -   35 
Total Revenues  1,952   406   113   35   364   131   3,001 
Production costs (3)
  390   42   10   6   52   49   549 
Exploration expense  122   44   1   -   17   3   187 
DD&A  595   25   18   11   81   20   750 
Impairment of assets  4   -   -   -   -   -   4 
Income before income taxes  841   295   84   18   214   59   1,511 
Income tax expense  191   84   14   4   114   10   417 
Results of operations (4)
 $650  $211  $70  $14  $100  $49   1,094 
Equity investee results of operations (5)
 $-  $128  $-  $-  $-  $-  $128 
Year Ended December 31, 2006                            
Revenues                            
Sales (2)
 $1,937  $414  $92  $-  $115  $143  $2,701 
Sales to affiliated power plant  -   -   -   34   -   -   34 
Total Revenues  1,937   414   92   34   115   143   2,735 
Production costs (3)
  420   32   9   6   22   42   531 
Exploration expense  113   7   -   -   11   12   143 
DD&A  571   23   14   12   9   26   655 
Impairment of assets  9   -   -   -   -   -   9 
Income before income taxes  824   352   69   16   73   63   1,397 
Income tax expense  313   125   20   4   42   23   527 
Results of operations (4)
 $511  $227  $49  $12  $31  $40  $870 
Equity investee results of operations (5)
 $-  $101  $-  $-  $-  $-  $101 
  United States  Equatorial Guinea  Israel  
Other Int'l (1)
  Total 
(millions)               
Year Ended December 31, 2009               
Revenues               
Sales (2)
 $1,341  $340  $144  $235  $2,060 
Sales to Affiliated Power Plant  -   -   -   35   35 
Total Revenues  1,341   340   144   270   2,095 
Production Costs (3)
  417   50   13   79   559 
Exploration Expense  75   1   10   24   110 
DD&A  689   38   21   50   798 
Asset Impairments  504   -   -   100   604 
Income before Income Taxes  (344)  251   100   17   24 
Income Tax Expense  (108)  59   20   6   (23)
Results of Operations (4)
 $(236) $192  $80  $11  $47 
Year Ended December 31, 2008                    
Revenues                    
Sales (2)
 $2,459  $500  $157  $535  $3,651 
Sales to Affiliated Power Plant  -   -   -   30   30 
Total Revenues  2,459   500   157   565   3,681 
Production Costs (3)
  470   42   12   123   647 
Exploration Expense  111   7   4   60   182 
DD&A  653   34   23   75   785 
Asset Impairments  224   -   -   -   224 
Income before Income Taxes  1,001   417   118   307   1,843 
Income Tax Expense  339   99   22   151   611 
Results of Operations (4)
 $662  $318  $96  $156  $1,232 
Year Ended December 31, 2007                    
Revenues                    
Sales (2)
 $1,952  $406  $113  $495  $2,966 
Sales to Affiliated Power Plant  -   -   -   35   35 
Total Revenues  1,952   406   113   530   3,001 
Production Costs (3)
  390   42   10   107   549 
Exploration Expense  122   26   1   38   187 
DD&A  595   25   18   112   750 
Asset Impairments  4   -   -   -   4 
Income before Income Taxes  841   313   84   273   1,511 
Income Tax Expense  191   84   14   128   417 
Results of Operations (4)
 $650  $229  $70  $145   1,094 
 
(1)Other International includes the North Sea, Ecuador, China, Cameroon, Cyprus, Argentina (through February 2008) and Suriname.other new ventures.
(2)
Includes impact resulting from applying cash flow hedge accounting for related commodity derivative instruments. See Note 6 -6. Derivative Instruments and Hedging Activities.
(3)Production costs from oil and gas producing activities consist of oil and gas operationslease operating expense, production and ad valorem taxes, transportation costs,expense, and general and administrative expense supporting oil and gas operations.
(4)
Results of operations from oil and gas producing activities exclude the mark-to-market gain or loss on commodity derivative instruments, corporate overhead and interest costs. See Note 6 -6. Derivative Instruments and Hedging Activities.
(5)Equity investee results of operations represents our share of the Alba Plant equity investee results of operations from oil and gas producing activities.

101112
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (Unaudited) (1)
Costs incurred in connection with crude oil and natural gas acquisition, exploration and development are as follows:
 
  United  West        North  Other    
  States  Africa  Israel  Ecuador  Sea  
Int'l (2)
  Total 
  (in millions) 
Year Ended December 31, 2008                     
Property acquisition costs                     
Proved (3)
 $256  $-  $-  $-  $-  $-  $256 
Unproved (4)
  296   -   -   -   1   5   302 
Total acquisition costs  552   -   -   -   1   5   558 
Exploration costs  322   110   28   1   17   39   517 
Development costs (5) (6) (7)
  1,106   41   13   1   94   10   1,265 
Total consolidated operations $1,980  $151  $41  $2  $112  $54  $2,340 
Our share of Alba Plant development costs $-  $2  $-  $-  $-  $-  $2 
Year Ended December 31, 2007                            
Property acquisition costs                            
Proved $11  $-  $-  $-  $-  $-  $11 
Unproved  145   -   -   -   -   1   146 
Total acquisition costs  156   -   -   -   -   1   157 
Exploration costs  184   179   2   -   52   3   420 
Development costs (5) (6) (7)
  1,081   15   25   -   47   23   1,191 
Total consolidated operations $1,421  $194  $27  $-  $99  $27  $1,768 
Our share of Alba Plant development costs $-  $1  $-  $-  $-  $-  $1 
Year Ended December 31, 2006                            
Property acquisition costs                            
Proved (8)
 $514  $8  $-  $-  $-  $-  $522 
Unproved (8)
  157   26   1   -   1   -   185 
Total acquisition costs  671   34   1   -   1   -   707 
Exploration costs  205   13   -   -   18   11   247 
Development costs (5) (6) (7)
  785   7   14   -   231   22   1,059 
Total consolidated operations $1,661  $54  $15  $-  $250  $33  $2,013 
Our share of Alba Plant development costs $-  $1  $-  $-  $-  $-  $1 
  United States  Equatorial Guinea  Israel  
Other Int'l (2)
  Total 
(millions)               
Year Ended December 31, 2009               
Property Acquisition Costs               
Proved (3)
 $(5) $-  $-  $-  $(5)
Unproved (4)
  89   1   -   2   92 
Total Acquisition Costs  84   1   -   2   87 
Exploration Costs (5)
  189   30   81   13   313 
Development Costs (6)
  711   100   33   129   973 
Total Consolidated Operations $984  $131  $114  $144  $1,373 
Year Ended December 31, 2008                    
Property Acquisition Costs                    
Proved (3)
 $256  $-  $-  $-  $256 
Unproved (4)
  296   -   -   6   302 
Total Acquisition Costs  552   -   -   6   558 
Exploration Costs (5)
  322   105   28   62   517 
Development Costs (6)
  1,106   38   13   108   1,265 
Total Consolidated Operations $1,980  $143  $41  $176  $2,340 
Year Ended December 31, 2007                    
Property Acquisition Costs                    
Proved $11  $-  $-  $-  $11 
Unproved  145   -   -   1   146 
Total Acquisition Costs  156   -   -   1   157 
Exploration Costs  184   131   2   103   420 
Development Costs (6)
  1,081   15   25   70   1,191 
Total Consolidated Operations $1,421  $146  $27  $174  $1,768 
 
(1)Costs incurred include capitalized and expensed items.
(2)Other International includes the North Sea, Ecuador, China, Cameroon, Cyprus, Argentina (through February 2008), Suriname and other new ventures.
(3)Includes2009 proved property acquisition costs include a $6 million downward purchase price adjustment related to the Mid-continent acquisition. 2008 proved property acquisition costs include $254 million related to the Mid-continent acquisition.
(4)Includes2009 unproved property acquisition costs include $56 million for deepwater Gulf of Mexico lease blocks and the remainder primarily for other onshore US lease acquisitions. 2008 unproved property acquisition costs include $179 million for deepwater Gulf of Mexico lease blocks, $38 million related to the Mid-continent acquisition, $39 million related to lease acquisitions in East Texas and the remainder primarily for other onshore US lease acquisitions.
(5)US development2009 exploration costs include increases in asset retirement obligationsdrilling and completion costs of $34$57 million in 2008, $24deepwater Gulf of Mexico, $19 million in 2007,Equatorial Guinea and $4$71 million in 2006. US asset retirementIsrael. 2008 exploration costs include drilling and completion costs of $33$72 million in 2006 were incurred as a resultdeepwater Gulf of hurricane damageMexico, $98 million in Equatorial Guinea and are excluded from the costs incurred schedule above as we recovered the costs from insurance proceeds.$25 million in Israel.
(6)
Worldwide development costs include amounts spent to develop proved undeveloped reserves of $1.0 billionapproximately $440 million in both2009, $528 million in 2008 and 2007, and $768$390 million in 2006. Worldwide2007. Equatorial Guinea development costs alsofor 2009 include $191a non-cash accrual of $29 million spentrelated to estimated construction progress to date on an FSPOFPSO to be used in the North Sea Dumbartondevelopment of the Aseng field in 2006.
(7)North SeaEquatorial Guinea. These capitalized costs will be included in development costs as the FPSO is constructed. US development costs include increases in asset retirement obligations of $11 million in 2009, $34 million in 2008 and $24 million in 2007. Other international development costs include increases in asset retirement obligations of $5 million in 2009, $18 million in 2008 and $4$9 million in 2007.
(8)
Includes amounts allocated from the U.S. Exploration acquisition (2006) See Note 4—Acquisitions and Divestitures.

102113
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Capitalized Costs Relating to Oil and Gas Producing Activities (Unaudited)
Aggregate capitalized costs relating to crude oil and natural gas producing activities, including asset retirement costs and related accumulated DD&A, are as follows:
 
  December 31, 
  2008  2007 
  (in millions) 
Unproved oil and gas properties (1)
 $961  $1,165 
Proved oil and gas properties (2)
  10,905   8,903 
Total oil and gas properties  11,866   10,068 
         
Accumulated DD&A  (3,022)  (2,281)
 Net capitalized costs $8,844  $7,787 
Our share of Alba Plant net capitalized costs $113  $117 
  December 31, 
  2009  2008 
(millions)      
Unproved Oil and Gas Properties (1)
 $874  $961 
Proved Oil and Gas Properties (2)
  11,710   11,002 
Total Oil and Gas Properties  12,584   11,963 
Accumulated DD&A  (3,809)  (3,054)
Net Capitalized Costs $8,775  $8,909 
 
(1)Unproved oil and gas properties includes $465$263 million and $628$465 million at December 31, 20082009 and 2007,2008, respectively, remaining from the allocation of costs to unproved properties acquired in the Patina Merger and the acquisition of U.S. Exploration.
(2)Proved oil and gas properties include asset retirement costs of $180$176 million and $91$180 million at December 31, 20082009 and 2007,2008, respectively.
 

103114
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (Unaudited)
The following information is based on our best estimate of the required data for the Standardized Measure of Discounted Future Net Cash Flows as of December 31, 2008, 2007 and 2006 in accordance with SFAS 69.US GAAP for extractive activities. The standard requiresstandards require the use of a 10% discount rate. This information is not the fair market value nor does it represent the expected present value of future cash flows of our proved oil and gas reserves.
 
  United  West        North  Other    
  States  Africa  Israel  Ecuador  Sea  
Int'l (1)
  Total 
  (in millions) 
December 31, 2008                     
Future cash inflows (2)
 $16,551  $3,277  $938  $674  $1,170  $455  $23,065 
Future production costs (3)
  4,646   784   120   249   442   185   6,426 
Future development costs  3,082   62   160   17   184   148   3,653 
Future income tax expense  2,594   774   173   119   305   49   4,014 
Future net cash flows  6,229   1,657   485   289   239   73   8,972 
10% annual discount for estimated timing of cash flows  3,180   608   106   157   14   43   4,108 
Standardized measure of discounted future net cash flows $3,049  $1,049  $379  $132  $225  $30  $4,864 
December 31, 2007                            
Future cash inflows (2)
 $30,733  $6,935  $858  $704  $2,492  $879  $42,601 
Future production costs (3)
  5,936   1,112   180   174   516   335   8,253 
Future development costs  3,136   202   88   12   200   15   3,653 
Future income tax expense  6,622   1,348   146   115   881   125   9,237 
Future net cash flows  15,039   4,273   444   403   895   404   21,458 
10% annual discount for estimated timing of cash flows  7,398   1,705   163   227   221   93   9,807 
Standardized measure of discounted future net cash flows $7,641  $2,568  $281  $176  $674  $311  $11,651 
December 31, 2006                            
Future cash inflows (2)
 $18,948  $4,904  $972  $629  $1,225  $808  $27,486 
Future production costs (3)
  4,551   738   146   162   327   187   6,111 
Future development costs  2,846   80   90   12   35   28   3,091 
Future income tax expense  3,422   1,348   187   130   435   177   5,699 
Future net cash flows  8,129   2,738   549   325   428   416   12,585 
10% annual discount for estimated timing of cash flows  3,966   1,132   215   170   95   120   5,698 
Standardized measure of discounted future net cash flows $4,163  $1,606  $334  $155  $333  $296  $6,887 
  United States  Equatorial Guinea  Israel  
Other Int'l (1)
  Total 
(millions)               
December 31, 2009               
Future Cash Inflows (2)
 $16,196  $5,151  $769  $2,832  $24,948 
Future Production Costs (3)
  5,390   1,185   96   983   7,654 
Future Development Costs  3,056   1,059   126   315   4,556 
Future Income Tax Expense  2,227   956   135   630   3,948 
Future Net Cash Flows  5,523   1,951   412   904   8,790 
10% Annual Discount for Estimated Timing of Cash Flows  2,672   814   93   279   3,858 
Standardized Measure of Discounted Future Net Cash Flows $2,851  $1,137  $319  $625  $4,932 
December 31, 2008                    
Future Cash Inflows (2)
 $16,551  $3,277  $938  $2,299  $23,065 
Future Production Costs (3)
  4,646   784   120   876   6,426 
Future Development Costs  3,082   62   160   349   3,653 
Future Income Tax Expense  2,594   774   173   473   4,014 
Future Net Cash Flows  6,229   1,657   485   601   8,972 
10% Annual Discount for Estimated Timing of Cash Flows  3,180   608   106   214   4,108 
Standardized Measure of Discounted Future Net Cash Flows $3,049  $1,049  $379  $387  $4,864 
December 31, 2007                    
Future Cash Inflows (2)
 $30,733  $6,935  $858  $4,075  $42,601 
Future Production Costs (3)
  5,936   1,112   180   1,025   8,253 
Future Development Costs  3,136   202   88   227   3,653 
Future Income Tax Expense  6,622   1,348   146   1,121   9,237 
Future Net Cash Flows  15,039   4,273   444   1,702   21,458 
10% Annual Discount for Estimated Timing of Cash Flows  7,398   1,705   163   541   9,807 
Standardized Measure of Discounted Future Net Cash Flows $7,641  $2,568  $281  $1,161  $11,651 
 
(1)Other International includes the North Sea, Ecuador, China and Argentina. We sold our Argentina assets in Argentina inFebruary 2008.
(2)The standardized measure of discounted future net cash flows for 2009, 2008 2007 and 20062007 does not include cash flows relating to anticipated future methanol or electricity sales.
(3)Production costs include oil and gas operationslease operating expense, production and ad valorem taxes, transportation costsexpense and general and administrative expense supporting oil and gas operations.
 

104115
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited)
Prices and Other Assumptions in Discounted Future Net Cash Flows (Unaudited)Future cash inflows are computed by applying year-end prices,a 12-month average commodity price, adjusted for location and quality differentials on a field-by-field basis, to year-end quantities of proved reserves, except in those instances where fixed and determinable price changes are provided by contractual arrangements at year-end. The discounted future cash flow estimates do not include the effects of derivative instruments. Average prices per region are as follows:
 
  United  West        North  Other    
  States  Africa  Israel  Ecuador  Sea  
Int'l (1)
  Total 
December 31, 2008                     
Average crude oil price per Bbl $36.62  $40.51  $-  $-  $45.17  $31.69  $37.97 
Average natural gas price per Mcf  4.99   0.25   3.43   3.74   5.72   -   3.39 
December 31, 2007                            
Average crude oil price per Bbl $88.00  $81.26  $-  $-  $93.79  $61.72  $85.62 
Average natural gas price per Mcf  6.78   0.27   2.69   3.74   7.07   -   4.36 
December 31, 2006                            
Average crude oil price per Bbl $57.02  $51.49  $-  $-  $57.81  $48.04  $54.87 
Average natural gas price per Mcf  5.32   0.27   2.70   3.75   7.11   0.85   3.48 
  United States  Equatorial Guinea  Israel  
Other Int'l (1)
  Total 
December 31, 2009 (2)
               
Average Crude Oil Price per Bbl $50.80  $53.46  $-  $59.55  $52.45 
Average Natural Gas Price per Mcf  3.64   0.25   3.28   3.69   2.52 
December 31, 2008                    
Average Crude Oil Price per Bbl $36.62  $40.51  $-  $40.05  $37.97 
Average Natural Gas Price per Mcf  4.99   0.25   3.43   3.82   3.39 
December 31, 2007                    
Average Crude Oil Price per Bbl $88.00  $81.26  $-  $82.20  $85.62 
Average Natural Gas Price per Mcf  6.78   0.27   2.69   4.04   4.36 
 
(1)Other International includes the North Sea, Ecuador, and China at December 31, 2009, 2008 and 2007 and 2006 andalso includes Argentina at December 31, 2007 and 2006.2007.

(2)The new SEC and FASB reserves reporting rules require the use of 12-month average commodity prices instead of year-end commodity prices.
We estimate that a $1.00 per Bbl change in the average price of crude oil or a $.10 per Mcf change in the average price of natural gas from the year-end12-month average prices at December 31, 2008for 2009 would change the discounted future net cash flows before income taxes by approximately $187$188 million or $168$150 million, respectively.
 
Future production and development costs, which include dismantlement and restoration expense, are computed by estimating the expenditures to be incurred in developing and producing the proved crude oil and natural gas reserves at the end of the year, based on year-end costs, and assuming continuation of existing economic conditions.
 
Future development costs include amounts that we expect to spend to develop proved undeveloped reserves of $745 million in 2009, $795$900 million in 2010, and $541$800 million in 2011.2011 and $500 million in 2012.
 
Future income tax expense is computed by applying the appropriate year-end statutory tax rates to the estimated future pretax net cash flows relating to proved crude oil and natural gas reserves, less the tax bases of the properties involved. Future income tax expense gives effect to tax credits and allowances, but does not reflect the impact of general and administrative costs and exploration expenses of ongoing operations.
 
Imbalance receivables and liabilities are as follows:
 
 Year Ended December 31,  Year Ended December 31, 
 2008  2007  2006  2009  2008  2007 
 (in millions) 
(millions)         
Imbalance receivables $7  $13  $18  $21  $7  $13 
Imbalance liabilities  8   10   17   12   8   10 
            
 
Imbalance receivables and imbalance liabilities have been excluded from the standardized measure of discounted future net cash flows.
 

105116
Noble Energy, Inc.
Supplemental Oil and Gas Information
(Unaudited)


Sources of Changes in Discounted Future Net Cash Flows (Unaudited)
Sources of Changes in Discounted Future Net Cash Flows (Unaudited)Principal changes in the aggregate standardized measure of discounted future net cash flows attributable to proved crude oil and natural gas reserves are as follows:
 
  Year Ended December 31, 
  2008  2007  2006 
  (in millions) 
Standardized measure of discounted future net cash flows, beginning of year $11,651  $6,887  $8,771 
Changes in standardized measure of dicounted future net cash flows:            
Sales of oil and gas produced, net of production costs  (3,030)  (2,427)  (2,177)
Net changes in prices and production costs  (8,017)  5,266   (2,788)
Extensions, discoveries and improved recovery, less related costs  400   1,635   769 
Changes in estimated future development costs  (883)  (775)  (558)
Development costs incurred during the period  1,291   1,189   1,076 
Revisions of previous quantity estimates  (617)  1,276   (92)
Purchases of minerals in place  182   6   573 
Sales of minerals in place  (66)  (95)  (579)
Accretion of discount  1,663   1,006   1,274 
Net change in income taxes  2,853   (1,900)  777 
Change in timing of estimated future production and other  (563)  (417)  (159)
Aggregate change in standardized measure of discounted future net cash flows  (6,787)  4,764   (1,884)
Standardized measure of discounted future net cash flows, end of year $4,864  $11,651  $6,887 
  Year Ended December 31, 
  2009  2008  2007 
(millions)         
Standardized Measure of Discounted Future Net Cash Flows, Beginning of Year $4,864  $11,651  $6,887 
Changes in  Standardized Measure of Discounted Future Net Cash Flows            
Sales of Oil and Gas Produced, Net of Production Costs  (1,528)  (3,030)  (2,427)
Net Changes in Prices and Production Costs  (878)  (8,017)  5,266 
Extensions, Discoveries and Improved Recovery, Less Related Costs  815   400   1,635 
Changes in Estimated Future Development Costs  (132)  (883)  (775)
Development Costs Incurred During the Period  971   1,291   1,189 
Revisions of Previous Quantity Estimates  436   (617)  1,276 
Purchases of Minerals in Place  5   182   6 
Sales of Minerals in Place  -   (66)  (95)
Accretion of Discount  707   1,663   1,006 
Net Change in Income Taxes  (75)  2,853   (1,900)
Change in Timing of Estimated Future Production and Other  (253)  (563)  (417)
Aggregate Change in Standardized Measure of Discounted Future Net Cash Flows  68   (6,787)  4,764 
Standardized Measure of Discounted Future Net Cash Flows, End of Year $4,932  $4,864  $11,651 
 


Supplemental Quarterly Financial Information (Unaudited)
 
Supplemental quarterly financial information is as follows:
 
   Quarter Ended 
   March 31,   June 30,   September 30,  December 31, Total 
   (in millions except per share amounts) 
2008 (1)
                   
Revenues $     1,025  $     1,205  $   1,098  $573 $        3,901 
Income (loss) before income taxes              315             (198)         1,454           490            2,061 
Net income (loss)              215             (144)            974           305            1,350 
                    
Earnings (loss) per share:                   
Basic (4)
 $         1.25  $       (0.84)  $      5.64  $1.77 $          7.83 
Diluted (2) (4)
             1.20            (0.84)           5.37   1.72              7.58 
2007 (3)
                   
Revenues $         743  $          794  $      814  $921 $       3,272 
Income before income taxes              304              293            344           427            1,368 
Net income              212              209            223           300               944 
                    
Earnings per share:                   
Basic (4)
 $       1.24  $        1.22  $       1.30  $1.75 $         5.52 
Diluted (4)
             1.22             1.21           1.28          1.73              5.45 
  Quarter Ended 
  March 31,  June 30,  Sep 30,  Dec 31,  Total 
(millions except per share amounts)               
2009 (1)
               
Revenues $441  $491  $621  $760  $2,313 
Income (Loss) Before Income Taxes  (374)  (90)  115   85   (264)
Net Income (Loss)  (188)  (57)  107   8   (131)
Earnings (Loss) Per Share                    
Basic (3)
 $(1.09) $(0.33) $0.62  $0.05  $(0.75)
Diluted (3)
  (1.09)  (0.33)  0.61   0.05  $(0.75)
2008 (2)
                    
Revenues $1,025  $1,205  $1,098  $573  $3,901 
Income (Loss) Before Income Taxes  315   (198)  1,454   490   2,061 
Net Income (Loss)  215   (144)  974   305   1,350 
Earnings (Loss) Per Share                    
Basic (3)
 $1.25  $(0.84) $5.64  $1.77  $7.83 
Diluted (3) (4)
  1.20   (0.84)  5.37   1.72   7.58 
 
(1)First quarter 2008 includes2009 included the following:
 ·$73 million gain on commodity derivative instruments. (See Note 6. Derivative Instruments and Hedging Activities);
·$437 million asset impairment charges (See Note 3. Asset Impairments); and
·$46 million reversal of Ecuador allowance for doubtful accounts (See Note 2. Summary of Significant Accounting Policies).
 Second quarter 2009 included the following:
·$139 million loss on commodity derivative instruments. (See Note 6. Derivative Instruments and Hedging Activities); and
·$24 million gain on sale of interest in Argentina, which had been deferred until government approval of the sale.
Third quarter 2009 included the following:
·$28 million loss on commodity derivative instruments (See Note 6. Derivative Instruments and Hedging Activities); and
·$12 million write-down of SemCrude, L.P. receivable (See Note 17. Commitments and Contingencies).
Fourth quarter 2009 included the following:
·$16 million loss on commodity derivative instruments (See Note 6. Derivative Instruments and Hedging Activities);
·$167 million asset impairment charges (See Note 3. Asset Impairments); and
·
$97 million refund of deepwater Gulf of Mexico royalties, including interest (See Note 2. Summary of Significant Accounting Policies).
(2)First quarter 2008 included the following:
·$237 million loss on commodity derivative instruments. (See(See Note 6–6. Derivative Instruments and Hedging Activities).
 
  Second quarter 2008 includesincluded the following:
 ·
$828 million loss on commodity derivative instruments. (See(See Note 6–6. Derivative Instruments and Hedging Activities).
 
 Third quarter 2008 includesincluded the following:
 ·
$875 million gain on commodity derivative instruments (See(See Note 6–6. Derivative Instruments and Hedging Activities);
 ·
$38 million write-down of SemCrude, L.P. receivable (See(See Note 17–17. Commitments and Contingencies);
and
 ·
$38 million asset impairment of assets (Seecharges (See Note 4–Acquisitions and Divestitures); and
·
$9 million loss on involuntary conversion (See Note 4–Acquisitions and Divestitures)3. Asset Impairments).
 
 Fourth quarter 2008 includesincluded the following:
 ·
$630 million gain on commodity derivative instruments (See(See Note 6–6. Derivative Instruments and Hedging Activities); and
 ·
$256 million asset impairment of assets (Seecharges (See Note 3–3. Asset Impairments).
(3)The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.
 
(2)(4)The diluted earnings per share calculations for the quarters ended September 30, 2008 and December 31, 2008 include decreases to net income of $29 million, net of tax, and $4 million, net of tax, respectively, related to deferred compensation gains related to shares of our common stock held in a rabbi trust.
(3)
First quarter 2007 includes the following:
·
$13 million loss on involuntary conversion (See Note 4—Acquisitions and Divestitures).
 Second quarter 2007 includes the following:
·
$38 million loss on involuntary conversion (See Note 4—Acquisitions and Divestitures).
(4)The sum of the individual quarterly earnings (loss) per share amounts may not agree with year-to-date earnings per share as each quarterly computation is based on the income or loss for that quarter and the weighted average number of shares outstanding during that quarter.



Item 9.  Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
 
None.
 
Item 9A.  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports we file or furnish to the SEC under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC’s rules and forms, and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
 
Our principal executive officer and principal financial officer have evaluated the effectiveness of our “disclosure controls and procedures,” as such term is defined in Rule 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this Annual Report on Form 10-K. Based upon their evaluation, they have concluded that our disclosure controls and procedures are effective.designed and effective to ensure that information required to be disclosed in the reports that we file or furnish under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified by the SEC's rules and forms and that information is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
 
In designing and evaluating our disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the control system will be met. In addition, the design of any control system is based in part upon certain assumptions about the likelihood of future events and the application of judgment in evaluating the cost-benefit relationship of possible controls and procedures. Because of these and other inherent limitations of control systems, there is only reasonable assurance that our controls will succeed in achieving their goals under all potential future conditions.
 
Management’s Annual Report on Internal Control over Financial Reporting
 
The management report called for by Item 308(a) of Regulation S-K is incorporated herein by reference to Management’s Report on Internal Control over Financial Reporting, included in Item 8. Financial Statements and Supplementary Data.
 
The independent auditor’s attestation report called for by Item 308(b) of Regulation S-K is incorporated herein by reference to Report of Independent Registered Public Accounting Firm (Internal Control Over Financial Reporting), included in Item 8. Financial Statements and Supplementary Data.
 
Changes in Internal Control over Financial Reporting
 
We have been in the process of implementing a new Enterprise Resource Planning (ERP) software system to replace our various legacy systems.  During 2008, we implemented additional phases of the system. As appropriate, we modified the designOur management is also responsible for establishing and documentation of internal control processes and procedures relating to the implementation of the newest phases.  We believe that the new ERP system has strengthened and will continue to enhance ourmaintaining adequate internal controls over financial reporting, as additional phases are implemented; however, there are inherent risksdefined in implementing any new system that could impactRules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting. See Item 1A. Risk Factors—Information technology systems implementation issues could disrupt our internal operations, increase our costsreporting and adversely affect ourthe preparation and presentation of the consolidated financial results or our ability to report our financial results.statements for external purposes in accordance with accounting principles generally accepted in the United States.
 
In the event that issues arise, we have manual procedures in place which would facilitate our continued recording and reporting of results from the new ERP system. However, becauseBecause of its inherent limitations, internal control over financial reporting may not detect or prevent misstatements. Projections of any evaluation of the 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.
 
We will continue to monitor, test, and appraiseOur management has assessed the impact and effecteffectiveness of the new ERP system on our internal controls and proceduresover financial reporting as additional phases and features of the system are implemented.December 31, 2009. Based on our assessment, our internal controls over financial reporting were effective. There were no changes in internal controls over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting, except as described above.reporting.
 
Item 9B.  Other Information
 
None.
 


PART III
 
Item 10.  Directors, Executive Officers and Corporate Governance
 
The information required by this item is incorporated herein by reference to the 20092010 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.2009.
 
Item 11.  Executive Compensation
 
The information required by this item is incorporated herein by reference to the 20092010 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.2009.
 
Item 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder  Matters
 
The information required by this item is incorporated herein by reference to the 20092010 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.2009.
 
Item 13.  Certain Relationships and Related Transactions, and Director Independence
 
The information required by this item is incorporated herein by reference to the 20092010 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.2009.
 
Item 14.  Principal Accounting Fees and Services
 
The information required by this item is incorporated herein by reference to the 20092010 Proxy Statement, which will be filed with the SEC not later than 120 days subsequent to December 31, 2008.2009.
 
PART IV
 
Item 15.  Exhibits, Financial Statements Schedules
 
a)       The following documents are filed as a part of this report:
 
(3)Exhibits: The exhibits required to be filed by this Item 15 are set forth in the Index to Exhibits accompanying this report.
 


SIGNATURES
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 NOBLE ENERGY, INC.
 
(Registrant)
 
Date: February 19, 200918, 2010By: /s/ Charles D. Davidson
 Charles D. Davidson,
 Chairman of the Board, President,
 
Chief Executive Officer and Director
 
Date: February 19, 200918, 2010By: /s/ Chris TongKenneth M. Fisher
 Chris Tong,Kenneth M. Fisher,
 
Senior Vice President, Chief Financial Officer
 
Date: February 19, 200918, 2010By: /s/ Frederick B. Bruning
 Frederick B. Bruning,
 Vice President, Chief Accounting Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated.
 
Signature   Capacity in which signed   Date  
/s/ Charles D. Davidson
 
Chairman of the Board, President,
 
February 19, 200918, 2010
Charles D. Davidson Chief Executive Officer and Director  
  
(Principal Executive Officer)
 
  
/s/ Chris TongKenneth M. Fisher Senior Vice President, February 19, 200918, 2010
Chris TongKenneth M. Fisher Chief Financial Officer  
  
(Principal Financial Officer)
 
  
/s/ Frederick B. Bruning Vice President, Chief Accounting Officer February 19, 200918, 2010
Frederick B. Bruning 
(Principal Accounting Officer)
 
  
/s/ Jeffrey L. Berenson Director February 19, 200918, 2010
Jeffrey L. Berenson
 
  
/s/ Michael A. Cawley Director February 19, 200918, 2010
Michael A. Cawley
 
  
/s/ Edward F. Cox Director February 19, 200918, 2010
Edward F. Cox
 
  
/s/ Thomas J. Edelman Director February 19, 200918, 2010
Thomas J. Edelman    
 
/s/ Eric P. Grubman
 
 
Director
 
 
February 19, 200918, 2010
Eric P. Grubman    
 
/s/ Kirby L. Hedrick
 
 
Director
 
 
February 19, 200918, 2010
Kirby L. Hedrick    
 
/s/ Scott D. Urban
 
 
Director
 
 
February 19, 200918, 2010
Scott D. Urban    
 
/s/ William T. Van Kleef
 
 
Director
 
 
February 19, 200918, 2010
William T. Van Kleef    



 



INDEX TO EXHIBITS
Exhibit
Number
   Exhibit** 
Exhibit **
3.1 — 
Certificate of Incorporation, as amended through May 16, 2005, of the Registrant filed herewith.
(filed as Exhibit 3.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008, and incorporated herein by reference).
3.2 — 
By-Laws of Noble Energy, Inc. as amended through December 9, 2008June 1, 2009 (filed as Exhibit 3.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 9, 2008)February 17, 2009) filed December 15, 2008February 19, 2009 and incorporated herein by reference).
4.1 — 
Certificate of Designations of Series A Junior Participating Preferred Stock of the Registrant dated August 27, 1997 (filed as Exhibit A of Exhibit 4.1 to the Registrant’s Registration Statement on Form 8-A filed on August 28, 1997 and incorporated herein by reference).
4.2 — 
Certificate of Designations of Series B Mandatorily Convertible Preferred Stock of the Registrant dated November 9, 1999 (filed as Exhibit 3.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1999 and incorporated herein by reference).
4.3 — 
Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant’s 8¼% Notes Due March 1, 2019 (filed as Exhibit 4.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 24, 2009) filed February 27, 2009 and incorporated herein by reference.)
4.4—First Supplemental Indenture dated as of February 27, 2009, to Indenture dated as of February 27, 2009 between Noble Energy, Inc. and Wells Fargo Bank, National Association, as Trustee, relating to the Registrant’s 8¼% Notes Due March 1, 2019 (including the form of 2019 Notes) (filed as Exhibit 4.2 to the Registrant’s Current Report on Form 8-K (Date of Event: February 24, 2009) filed February 27, 2009 and incorporated herein by reference).
4.5—Indenture dated as of October 14, 1993 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee, relating to the Registrant’s 7 1/4%7¼% Notes Due 2023, including form of the Registrant’s 7 1/4%7¼% Notes Due 2023 (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 1993 and incorporated herein by reference).
4.44.6 — 
Indenture relating to Senior Debt Securities dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference).
4.54.7 — 
First Indenture Supplement relating to $250 million of the Registrant’s 8% Senior Notes Due 2027 dated as of April 1, 1997 between the Registrant and U.S. Trust Company of Texas, N.A., as Trustee (filed as Exhibit 4.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended March 31, 1997 and incorporated herein by reference).
4.64.8 — 
Second Indenture Supplement, between the Company and U.S. Trust Company of Texas, N.A. as trustee, relating to $100 million of the Registrant’s 7 1/4%7¼% Senior Debentures Due 2097 dated as of August 1, 1997 (filed as Exhibit 4.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1997 and incorporated herein by reference).
4.74.9 — 
Third Indenture Supplement relating to $200 million of the Registrant’s 5.25%5¼% Notes due 2014 dated April 19, 2004 between the Company and the Bank of New York Trust Company, N.A., as successor trustee to U.S. Trust Company of Texas, N.A. (filed as Exhibit 4.1 to the Company’s Registration Statement on Form S-4 (Registration No. 333-116092) and incorporated herein by reference).
10.1* — 
Noble Energy, Inc. Retirement Restoration Plan dated effective as of January 1, 2009, filed herewith.
(filed as Exhibit 10.1 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
10.2* — 
Noble Energy, Inc. Restoration Trust effective August 1, 2002 (filed as Exhibit 10.3 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference).
10.3* — 
Form of Nonqualified Stock Option Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference).
10.4* — 
Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, filed herewith.
(filed as Exhibit 10.4 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
10.5* — 
1988 Nonqualified Stock Option Plan for Non-Employee Directors of the Registrant, as amended and restated, effective as of April 27, 2004 (filed as Exhibit 10.2 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 and incorporated herein by reference).
10.6* — 
Form of Indemnity Agreement entered into between the Registrant and each of the Registrant’s directors and bylaw officers (filed as Exhibit 10.18 to the Registrant’s Annual Report of Form 10-K for the year ended December 31, 1995 and incorporated herein by reference).
10.710.7* — 
Guaranty of the Registrant dated October 28, 1982, guaranteeing certain obligations of Samedan (filed as Exhibit 10.12 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 1993 and incorporated herein by reference).
10.8*—
Letter agreement dated February 1, 2002 between the Registrant and Charles D. Davidson, terminating Mr. Davidson’s employment agreement and entering into the attached Change of Control Agreement (filed as Exhibit 10.17 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2001 and incorporated herein by reference).
10.910.8 — 
364-day Credit Agreement dated as of November 27, 2002 among the Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent for the lenders, Societe Generale, Citibank, N.A., Deutsche Bank Ag New York Branch, and The Royal Bank of Scotland PLC, as co-documentation agents, and certain commercial lending institutions, as lenders, (filed as Exhibit 10.19 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2002 and incorporated herein by reference).
INDEX TO EXHIBITS
Exhibit
Number
Exhibit** 
10.10—
364-day Credit Agreement dated as of October 30, 2003 among the Registrant, as borrower, JPMorgan Chase Bank, as the administrative agent for the lenders, Wachovia Bank, National Association, as the syndication agent for the lenders, Societe Generale, Deutsche Bank Ag New York Branch, and The Royal Bank of Scotland PLC, as co-documentation agents, and certain commercial lending institutions, as lenders (filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2003 and incorporated herein by reference).
10.11—
Term Loan Agreement dated as of January 30, 2004 among Noble Energy Mediterranean Ltd., as borrower, Sumitomo Mitsui Banking Corporation, as initial lender and agent for the lenders, and certain commercial lending institutions, as lenders (filed as Exhibit 99.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.12—
Guaranty of the Company dated January 30, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated January 30, 2004 (filed as Exhibit 99.2 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.13—
Term Loan Agreement dated as of February 2, 2004 among Noble Energy Mediterranean Ltd., as borrower, Bank One, NA, as agent for the lenders, and certain commercial lending institutions, as lenders (filed as Exhibit 99.3 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.14—
Guaranty of the Company dated February 2, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated February 2, 2004 (filed as Exhibit 99.4 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.15—
Term Loan Agreement dated as of February 4, 2004 among Noble Energy Mediterranean Ltd., as borrower, The Royal Bank of Scotland Finance (Ireland), as agent for the lenders and as the initial lender (filed as Exhibit 99.5 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.16—
Guaranty of the Company dated February 4, 2004 guaranteeing obligations of Noble Energy Mediterranean, Ltd. under the Term Loan Agreement dated February 4, 2004 (filed as Exhibit 99.6 to the Registrant’s Current Report on Form 8-K (Date of Event: January 30, 2004) filed May 10, 2004 and incorporated herein by reference).
10.17*—
Form of Performance Units Agreement under the Noble Energy, Inc. 2004 Long-Term Incentive Plan (filed as Exhibit 10.3 to the Registrant’s Current Report on Form 8-K (Date of Event: February 1, 2005) filed February 7, 2005 and incorporated herein by reference).
10.18—
$2.1 billion Five-Year Credit Agreement, dated December 9, 2005, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as co-syndication agents, Deutsche Bank Securities Inc. and Citibank, N.A., as co-documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: December 9, 2005), filed December 14, 2005 and incorporated herein by reference).
10.19—
$2.1 billion Five-Year Credit Agreement, dated November 30, 2006, among Noble Energy, Inc., JPMorgan Chase Bank, N.A., as administrative agent, Wachovia Bank, National Association and The Royal Bank of Scotland PLC, as co-syndication agents, Deutsche Bank Securities Inc., Citibank, N.A. and The Bank of Tokyo-Mitsubishi UFJ, Ltd., as co-documentation agents, and certain other commercial lending institutions named therein (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: November 30, 2006), filed December 6, 2006 and incorporated herein by reference).
10.20*10.9* — 
Noble Energy, Inc. 2005 Non-Employee Director Fee Deferral Plan, dated December 11, 2008, and effective as of January 1, 2009, filed herewith.
(filed as Exhibit 10.20 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2008 and incorporated herein by reference).
10.21*10.10* — 
Consulting Agreement, dated May 9, 2005 but commencing May 16, 2005, by and between Noble Energy, Inc. and Thomas J. Edelman (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: May 16, 2005), filed May 20, 2005 and incorporated herein by reference).
10.22*—
2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: April 26, 2005) filed April 29, 2005 and incorporated herein by reference).
10.23*10.11* — 
Form of Stock Option Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference).
10.24*10.12* — 
Amendment to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (effective September 1, 2008) (filed as Exhibit to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).
10.13*—Form of Restricted Stock Agreement under the Noble Energy, Inc. 2005 Non-Employee Director Stock Plan (filed as Exhibit 10.1 to the Registrant’s Current Report on Form 8-K (Date of Event: January 27, 2009) filed on February 2, 2009 and incorporated herein by reference).


122

10.25*10.14* — 
Form of Restricted Stock Agreement under the Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan, entered into by certain executive officers and key employees of the Company on May 16, 2005 and August 1, 2005, respectively (filed as Exhibit 10.4 to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2005 and incorporated herein by reference).
filed herewith.
10.26*10.15* — 
Noble Energy, Inc. 1992 Stock Option and Restricted Stock Plan (as amended through April 24, 2007)28, 2009), (filed as exhibit 10.1 to Registrant’s Current Report on Form 8-K (Date of Event: April 24, 2007)28, 2009) filed April 30, 200729, 2009 and incorporated herein by reference).

112

INDEX TO EXHIBITS
Exhibit
Number
Exhibit** 
10.27*10.16* — 
Noble Energy, Inc. Change of Control Severance Plan for Executives (as amended effective January 1, 2008), (filed as Exhibit 10.40 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).
10.28*10.17* — 
Noble Energy, Inc. Change of Control Agreement (as amended effective January 1, 2008), (filed as Exhibit 10.41 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).
10.29*10.18* — 
Noble Energy, Inc. 2004 Long-Term Incentive Plan (as amended effective January 1, 2008), (filed as Exhibit 10.42 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).
10.30*10.19* — 
Amendment to the 2006 Performance Units AgreementNoble Energy, Inc. 2005 Deferred Compensation Plan (as amended effective January 1, 2008)2009), (filed as Exhibit 10.4310.31 to the Registrant’s Annual Report on Form 10-K for the year ended December 31, 2007 and incorporated herein by reference).
10.31*—
Noble Energy, Inc. 2005 Deferred Compensation Plan (as amended effective January 1, 2009), filed herewith.
10.32*—
Amendment to the 2005 Stock Plan for Non-Employee Directors of Noble Energy, Inc. (effective September 1, 2008) (filed as Exhibit to the Registrant’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2008 and incorporated herein by reference).
12.1 — 
Calculation of ratio of earnings to fixed charges, filed herewith.
21 — 
Subsidiaries, filed herewith.
23.1 — 
Consent of Independent Registered Public Accounting Firm—KPMG LLP, filed herewith.
23.2 — 
Consent of Independent Registered Public Accounting Firm—PricewaterhouseCoopers LLP, filed herewith.
23.3 — 
Consent of Independent Petroleum Engineers and Geologists—Netherland, Sewell & Associates, Inc., filed herewith.
31.1 — 
Certification of the Company’s Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
, filed herewith.
31.2 — 
Certification of the Company’s Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 7241).
, filed herewith.
32.1 — 
Certification of the Company’s Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
, filed herewith.
32.2 — 
Certification of the Company’s Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (18 U.S.C. Section 1350).
, filed herewith.
99.1 — 
Report of Independent Public Accounting Firm—PricewaterhouseCoopers LLP, filed herewith.
99.2 — 
Report of Netherland, Sewell & Associates, Inc., filed herewith.
101—The following materials from the Noble Energy, Inc. Annual Report on Form 10-K for the year ended December 31, 2009, formatted in XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Operations, (ii) the Consolidated Balance Sheets, (iii) the Consolidated Statements of Cash Flows, (iv) the Consolidated Statements of Shareholders’ Equity, (v) Consolidated Statements of Comprehensive Income and (vi) Notes to the Consolidated Financial Statements, tagged as blocks of text.
     
  *Management contract or compensatory plan or arrangement required to be filed as an exhibit hereto.
  **Copies of exhibits will be furnished upon prepayment of 25 cents per page. Requests should be addressed to the Senior Vice President and Chief Financial Officer, Noble Energy, Inc., 100 Glenborough Drive, Suite 100, Houston, Texas 77067.




GLOSSARY
 
In this report, the following abbreviations are used:
 
Bbl(s)Barrel(s)
MBblsBcfThousand barrelsBillion cubic feet
MMBblsBcfeMillion barrels
BpdBarrels per day
BopdBarrels oil per dayBillion cubic feet equivalent
BoeBarrels oil equivalent; gas is converted on the basis of six Mcf of gas per one barrel of oil, condensate or natural gas liquids
MBoeThousand barrels oil equivalent
MMBoeMillion barrels oil equivalent
BoepdBarrels oil equivalent per day
MMgalBopdMillion gallonsBarrels oil per day
KWBpdKilowattBarrels per day
BtuBritish thermal unit
GWGigawatt
KWhKilowatt hours
MWLNGMegawattLiquefied natural gas
GW
Mcf
LPG
Gigawatt
Thousand cubic feet
Liquefied petroleum gas
MMcfMBblsMillion cubic feetThousand barrels
BcfMBoeBillion cubic feetThousand barrels oil equivalent
TcfMBoepdTrillion cubic feetThousand barrels oil equivalent per day
McfpdMBopdThousand barrels per day
MBpdThousand barrels per day
McfThousand cubic feet per day
MMcfpdMillion cubic feet per day
McfeThousand cubic feet equivalent
MMcfeMMBblsMillion cubic feet equivalentbarrels
BcfeMMBoeBillion cubic feetMillion barrels oil equivalent
BTUBritish thermal unit
MMBtuMillion British thermal units
MMBtupdMillion British thermal units per day
BtupcfMMcfBritish thermal unit perMillion cubic footfeet
MTMMcfeMetric tonsMillion cubic feet equivalent
MMcfepdMillion cubic feet equivalent per day
MMcfpdMillion cubic feet per day
MMgalMillion gallons
MTpdMetric tons per day
LNGMWLiquefied natural gas
LPGLiquefied petroleum gasMegawatt
NGLNatural gas liquid
TcfeTrillion cubic feet equivalent

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