form10k.htm


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K

(Mark One)
T
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2010
or
o
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from          to
Commission file number: 001-07964

Logo 1
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

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. T 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 T 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. T 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). T 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. T

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 “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer T
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 T No

Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2010: $10.4 billion.
Number of shares of Common Stock outstanding as of January 31, 2011: 175,746,518.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2011 Annual Meeting of Stockholders to be held on April 26, 2011, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2010, are incorporated by reference into Part III.
 


 
 

 

TABLE OF CONTENTS

PART I
Items 1. and 2. 
3
Item 1A.
23
Item 1B.
35
Item 3.
35
Item 4.
35
 
36
PART II
Item 5.
38
Item 6.
41
Item 7.
42
Item 7A.
70
Item 8.
71
Item 9.
122
Item 9A.
122
Item 9B.
122
PART III
Item 10.
123
Item 11.
123
Item 12.
123
Item 13.
123
Item 14.
123
PART IV
Item 15.
123


GLOSSARY

In this report, the following abbreviations are used:

Bbl
Barrel
MBbls
Thousand barrels
MMBbls
Million barrels
MBbl/d
Thousand barrels per day
BOE
Barrels of oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given recent commodity price disparities, the price for a barrel of oil equivalent for natural gas is less than the price for a barrel of oil.
MBoe
Thousand barrels oil equivalent
Boe/d
Barrels oil equivalent per day
MBoe/d
Thousand barrels oil equivalent per day
Mcf
Thousand cubic feet
MMcf
Million cubic feet
Bcf
Billion cubic feet
MMcf/d
Million cubic feet per day
Mcfe
Thousand cubic feet equivalent
MMcfe
Million cubic feet equivalent
Btu
British thermal unit
MMBtu
Million British thermal units
MMgal
Million gallons
LNG
Liquefied natural gas
LPG
Liquefied petroleum gas
NGL
Natural gas liquid
FPSO
Floating production, storage and offloading vessel


PART I

Items 1. 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. See Item 1A. Risk Factors – Disclosure Regarding Forward-Looking Statements of this Form 10-K.

General

Noble Energy, Inc. (Noble Energy, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Noble Energy is a Delaware corporation, formed in 1969, that has been publicly traded on the New York Stock Exchange (NYSE) since 1980. In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy and its subsidiaries.

Our aim is to achieve growth in earnings and cash flow through exploration success and the development of a high quality, diversified portfolio of assets that is balanced between US and international projects. Exploration success, along with additional capital investment in US and international locations such as Equatorial Guinea and Israel, has resulted in a visible lineup of major development projects which positions us for substantial future reserves growth. Occasional strategic acquisitions of producing and non-producing properties, such as the Central Denver - Julesberg (DJ) Basin asset acquisition in 2010, combined with the divestment of non-core assets, have allowed us to achieve our objective of a well-balanced and diversified asset portfolio. Our portfolio is balanced between short-term and long-term projects, both onshore and offshore. Onshore US assets provide a stable base of production and accommodate flexible capital spending programs that are responsive to ongoing changes in the economic environment.  Our long-term development projects, while requiring multi-year capital investment, are expected to offer attractive financial returns and sustained production growth, along with a diversity of production mix among crude oil, US natural gas, and international natural gas.

We have operations in four key areas:

 
·
the Central DJ Basin onshore US;
 
·
the deepwater Gulf of Mexico;
 
·
offshore West Africa; and
 
·
offshore Eastern Mediterranean.

These areas provide:

 
·
most of our crude oil and natural gas production;
 
·
visible growth from major development projects; and
 
·
numerous exploration opportunities.

Our growth is supported by a strong balance sheet and ample liquidity levels. See Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2006-2010.

Major Development Project Inventory   Our exploration success has provided us with a number of major development projects on which we are moving forward. Although these projects will require significant capital investments over the next several years, they typically offer long life, sustained cash flows after investment and attractive financial returns. Our major development projects include the following:

 
·
Central DJ Basin (onshore US);
 
·
Galapagos (deepwater Gulf of Mexico);
 
·
Gunflint (deepwater Gulf of Mexico);
 
·
Tamar (offshore Israel);
 
·
Aseng (offshore Equatorial Guinea);
 
·
Alen (offshore Equatorial Guinea);
 
·
Diega/Carmen (offshore Equatorial Guinea); and
 
·
West Africa gas projects (offshore Equatorial Guinea and Cameroon).

These projects are discussed in more detail in the sections below. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Major Development Project Inventory.


Proved Oil and Gas Reserves    Proved reserves estimates at December 31, 2010 were as follows:

Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices

   
December 31, 2010
 
   
Proved Reserves
 
   
Crude Oil, Condensate & NGLs
   
Natural Gas
   
Total (1)
 
Reserves Category
 
(MMBbls)
   
(Bcf)
   
(MMBoe)
 
                   
Proved Developed
                 
United States
    119       1,156       312  
Equatorial Guinea
    43       597       142  
Israel
    -       145       24  
Other International (2)
    21       19       24  
Total Proved Developed Reserves
    183       1,917       502  
Proved Undeveloped
                       
United States
    106       470       184  
Equatorial Guinea
    69       272       114  
Israel
    2       1,699       286  
Other International (2)
    5       3       6  
Total Proved Undeveloped Reserves
    182       2,444       590  
Total Proved Reserves
    365       4,361       1,092  

(1)
Natural gas is converted on the basis of six Mcf of gas per one barrel of oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency.

(2)
Other international includes the North Sea and China.

Estimated reserves at the end of 2010 were approximately 1.1 billion barrels of oil equivalent, a 33% increase from 2009. US reserves accounted for 45% of the total, and international reserves accounted for 55%. Our 2010 reserve mix is 33% global liquids, 42% international natural gas, and 25% US natural gas.

See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental 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 exploration 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 onshore US and in the deepwater Gulf of Mexico, West Africa and the Eastern Mediterranean, resulting in a significant portfolio of major development projects. In December 2010, we announced a significant natural gas discovery at the Leviathan prospect, offshore Israel, our largest discovery to date. We have numerous exploration opportunities remaining in these areas and are also engaged in new venture activity in the US and international locations.

Appraisal, Development and Exploitation Activities   Our exploration success has delivered numerous development opportunities, as demonstrated in our growing inventory of major development projects.  In 2010, we sanctioned the development plans for the Tamar and Alen projects.
 
Acquisition and Divestiture Activities   We maintain an ongoing portfolio management 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, non-strategic assets in order to optimize our property portfolio.

Central DJ Basin Asset Acquisition On March 1, 2010, we acquired substantially all of the US Rocky Mountain assets of Petro-Canada Resources (USA) Inc. and Suncor Energy (Natural Gas) America Inc. for a total purchase price of $498 million. The acquisition included properties located in the Central DJ Basin, one of our key operating areas. The acquisition added approximately 46 MMBoe of proved reserves at closing date, and approximately 10 MBoe/d to our daily production base, starting from the closing date, and will provide significant growth potential. Included in the purchase were 323,000 total net acres, nearly 183,000 of which are located in the Central DJ Basin. See United States discussion below.


Onshore US Sale   In August 2010, we closed the sale of non-core assets in the Mid-Continent and Illinois Basin areas for cash proceeds of $552 million and recorded a gain of $110 million.  The sale included approximately 32 MMBoe of proved reserves, at closing date, and approximately 5.7 MBoe/d of production.

Mid-Continent Acquisition   In 2008, we acquired producing properties in western Oklahoma for $292 million. Properties acquired cover approximately 15,500 net acres and included approximately 16 MMBoe of proved reserves.

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. Our crude oil reserves for Argentina totaled 7 MMBbls at December 31, 2007.

Deepwater Horizon Incident   In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for another operator, sank after a blowout and fire (Deepwater Horizon Incident or Incident). The resulting leak caused a significant oil spill. Subsequently, the Secretary of the Interior ceased issuing offshore drilling permits pursuant to a series of moratoria, and all deepwater drilling activities in progress were suspended (Deepwater Moratorium). Although the moratoria have been lifted for drilling in water depths greater than 500 feet, the US Department of the Interior has not issued any permits related to the drilling of new exploratory wells as of January 31, 2011. Additionally, the US administration and the Department of the Interior have maintained the ban on new drilling on the Atlantic Coast and in the Eastern Gulf of Mexico.

The Deepwater Horizon Incident is likely to have a significant and lasting effect on the US offshore energy industry, and has resulted in a number of fundamental changes, including heightened regulatory scrutiny, more stringent operating and safety standards and changes in equipment requirements. Other countries, including some in which we currently conduct business, are considering legislative or regulatory changes which could also have an impact on offshore drilling activities.  These changes may result in increases in our operating and development costs and extend project development timelines. We are monitoring legislative and regulatory developments and are currently unsure of the full impact of the Incident.

See Deepwater Gulf of Mexico, below, and Item 1A. Risk Factors Our operations in the deepwater Gulf of Mexico, as well as onshore US and international locations, could be adversely affected by future changes in laws and regulations which may occur as a result of the Deepwater Horizon Incident.

Termination of Ecuador PSC In November 2010, we announced that we had received notice from the government of Ecuador regarding the termination of the Block 3 production sharing contract (PSC) (100% working interest) with our subsidiary, EDC Ecuador Ltd. as we had not negotiated a service contract on Block 3 in accordance with the terms of a newly enacted hydrocarbon law. The Ecuadorian hydrocarbon law aims to change current production sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010. It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.

We are continuing to work with the government of Ecuador to resolve this matter. However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of our investment in Ecuador which, as of December 31, 2010, had a net book value of approximately $66 million.

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. US operations accounted for 57% of our 2010 total consolidated sales volumes and 45% of total proved reserves at December 31, 2010. Approximately 55% of the proved reserves are natural gas and 45% are crude oil, condensate and NGLs.

Sales of production and estimates of proved reserves for our US operating areas were as follows:

   
Year Ended December 31, 2010
   
December 31, 2010
 
   
Sales Volumes
   
Proved Reserves
 
   
Crude Oil & Condensate
   
Natural Gas
   
NGLs
   
Total
   
Crude Oil, Condensate & NGLs
   
Natural Gas
   
Total
 
   
(MBbl/d)
   
(MMcf/d)
   
(MBbl/d)
   
(MBoe/d)
   
(MMBbls)
   
(Bcf)
   
(MMBoe)
 
Wattenberg
    19       151       10       54       177       851       319  
Rocky Mountain/Mid-Continent
    5       171       1       36       16       646       123  
Deepwater Gulf of Mexico
    11       40       2       19       22       34       28  
Gulf Coast and Other Onshore
    4       38       1       10       10       95       26  
Total
    39       400       14       119       225       1,626       496  


Wells drilled in 2010 and productive wells at December 31, 2010 for our US operating areas were as follows:

   
Year Ended December 31, 2010
   
December 31, 2010
 
   
Gross Wells Drilled or Participated in
   
Gross Productive Wells
 
Wattenberg
    491       7,706  
Rocky Mountain/Mid-Continent
    177       4,346  
Deepwater Gulf of Mexico (1)
    1       11  
Gulf Coast and Other Onshore
    20       1,284  
Total
    689       13,347  

(1)
Excludes Deep Blue and Santiago exploratory wells where drilling activities were suspended by the Deepwater Moratorium.


Locations of our onshore US operations are shown on the map below:

Map 1
 
Central DJ Basin / Wattenberg   Our onshore activities are focused in the Central DJ Basin, where we have a significant acreage position of over 830,000 net acres. Included in the Central DJ Basin is Wattenberg (approximately 97% operated working interest), our largest US onshore asset. We have a multi-year project inventory, enhanced in 2010 with the Central DJ Basin asset acquisition, and have added a horizontal drilling program targeting the Niobrara formation.

Wattenberg includes:

 
·
our historical Wattenberg development area, where we have conducted substantial vertical development over the last several years and are now identifying locations for additional horizontal wells;
 
·
the northern and eastern edges of our historical Wattenberg development area where we are focusing on expanding the economic limits of the area. Expansion of this area has resulted in increases in our crude oil and NGL production volumes. Most of our recent horizontal drilling has been in this area; and
 
·
Northern Colorado from the edge of our historical Wattenberg development area to the Wyoming border.

During 2010, we drilled a total of 463 successful development wells in the Codell/Niobrara, J-Sand, and Lyons formations in historical Wattenberg. Seventeen of these wells were drilled horizontally into the Niobrara formation and one was drilled horizontally into the Codell formation.

Historical Wattenberg contributed 52.7 MBoe/d of production and represented approximately 25% of total consolidated sales volumes in 2010, with over 50% being liquids, and approximately 314 MMBoe or 29% of total proved reserves at December 31, 2010.

We also drilled 24 successful development wells in the J-Sand formation and four successful horizontal exploratory wells in the Niobrara formation in Northern Colorado.

Our 2010 Wattenberg drilling program resulted in additions to proved reserves of approximately 36 MMBoe, approximately 64% of which are liquids.

We have also started a horizontal drilling program on acreage in Southeastern Wyoming.


At year-end, we were running six vertical rigs, two horizontal rigs and 23 completion units and are evaluating processing and transportation infrastructure needs as well as optimum well completion techniques. We expect to add three horizontal rigs and drill approximately 80 horizontal and 500 vertical wells in the Central DJ Basin in 2011.

Piceance Basin   We currently hold interests in approximately 20,000 net acres in the Piceance Basin in western Colorado (approximately 87% operated working interest), providing an inventory of future projects. 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.  In 2010, we drilled 62 development wells, 100% of which were successful. Successful drilling activity in recent years has led to significant volume growth; production has grown from 2 MMcfe/d in 2005 to 49 MMcfe/d for 2010. We plan to drill approximately 20 wells in 2011.

Wind River Basin   At our Iron Horse development in the Wind River Basin (99% operated working interest), located in Central Wyoming, we drilled nine development wells during 2010 with a 100% success rate.  We plan to continue our drilling program here during 2011 and expect to drill approximately three new wells.

Mid-Continent Area   The Mid-Continent area includes properties in the Texas Panhandle, Oklahoma and Kansas. A significant area of activity has been in the liquid-rich Cleveland Sandstone area of western Oklahoma (89% operated working interest). We drilled or participated in a total of 33 development wells in these areas in 2010. Twelve of the wells were horizontal development wells, 100% of which were successful. We currently have one rig operating and expect to drill approximately six wells in 2011.

Bowdoin, Tri-State and San Juan   We also produce in the Bowdoin Field (approximately 70% operated working interest) located in North Central Montana, Tri-State Field (approximately 95% operated working interest) in northeastern Colorado, northwestern Kansas, and southwestern Nebraska, and the San Juan Basin (approximately 82% operated working interest) located in northwestern New Mexico and southwestern Colorado. We have reduced investment in these areas in order to focus our capital spending on the core development fields. During 2010, we drilled 72 development wells and one exploratory well in these areas.

Onshore East Texas and North Louisiana (Haynesville)   We hold approximately 17,000 gross acres in the Haynesville/Bossier core area. A majority of our 2010 drilling program targeted the Haynesville/Bossier shale (approximately 60% working interest). We drilled or participated in nine development and two exploratory wells in the Haynesville/Bossier shale with an overall success rate of 100%.  The majority of our acreage is now held by production.

Other   We drilled or participated in an additional eight development wells and one exploratory well in other onshore US areas in 2010.

Deepwater Gulf of Mexico   The deepwater Gulf of Mexico is one of our key operating areas. Our focus is on high-impact opportunities with the potential to provide significant medium and long-term growth. We have three producing fields, multiple ongoing development projects and a substantial inventory of exploration opportunities.

The deepwater Gulf of Mexico accounted for 9% of total consolidated sales volumes in 2010 and 3% of total proved reserves at December 31, 2010. We currently hold leases on 108 deepwater Gulf of Mexico blocks, representing almost 600,000 gross acres (425,000 net acres). We are the operator on approximately 85% of the leases.


Locations of our deepwater Gulf of Mexico developments are shown on the map below:

Map 2
 
Deepwater Gulf of Mexico Exploration Program   Our deepwater Gulf of Mexico operations resulted from lease acquisition, expansion of our 3-D seismic database, and an active drilling program prior to the Deepwater Moratorium and current permitting environment. We currently have an inventory of 41 identified prospects, with a combination of both large stand-alone prospects as well as a number of smaller, tie-back opportunities.

During 2010, prior to the Deepwater Moratorium, we continued drilling efforts on two significant test wells that had been spud in 2009, Double Mountain (Green Canyon Block 555; 30% non-operated working interest) and Deep Blue (Green Canyon Block 723; 33.75% operated working interest).  In April 2010 we announced that the exploration well at the Double Mountain prospect had found noncommercial quantities of hydrocarbons and was plugged and abandoned.

When the Deepwater Moratorium was announced in May 2010, we were required to suspend sidetrack drilling activities at the Deep Blue prospect.  We also were required to suspend drilling activities at the Santiago exploratory well (23.25% operated working interest) at the Galapagos project. Once drilling permits are approved, we plan to resume exploration activities at Deep Blue and Santiago and appraisal drilling at Gunflint in 2011.

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)   Gunflint is a 2008 crude oil discovery, our largest deepwater Gulf of Mexico discovery to date. Our plans to drill one or two appraisal wells during 2010 were delayed by the Deepwater Moratorium. Once a drilling permit is approved, we plan to conduct appraisal drilling to help define the extent of the reservoir and a potential development scenario.

We are reviewing host platform options including: subsea tieback to existing third-party host, procurement and modification of existing platform, and new construction. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule, thereby potentially absorbing time lost due to the Deepwater Moratorium and permit-related delay. We are currently targeting 2015 for production start-up.

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)   The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and the Santiago exploration well (Mississippi Canyon Block 519, 23.25% operated working interest).  In 2009, we approved a phased development plan which includes completion of the wells and connection to the nearby Nakika production platform via subsea tieback. Nakika is partially owned and operated by BP Exploration & Production Inc. (BP).  During the last half of 2010, we assumed operatorship of the Isabela well completion from BP and were able to obtain permits to perform completion work at both Isabela and Santa Cruz. Although installation of the Nakika topside equipment is not expected to be completed until 2012, we are working on alternatives which may result in commencement of production in late 2011 or early 2012.
 

Raton/Raton South/Redrock (Mississippi Canyon Blocks 204, 248 and 292)   Raton (67% operated working interest) was a 2006 natural gas discovery and has been producing since 2008. Raton South (79% operated working interest) was a 2008 crude oil discovery. Raton South is in the process of being tied back to a non-operated host facility and is expected to commence production by the end of 2011.  Redrock (67% operated working interest) was a 2006 natural gas/condensate discovery. We plan to tie back Redrock after Raton South commences production.

Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest)   Swordfish was a 2001 discovery and began producing in 2005. After a 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.

Ticonderoga (Green Canyon block 768; 50% non-operated working interest)   Ticonderoga is a 2004 crude oil discovery and began producing in 2006. The project currently includes three producing wells connected to existing infrastructure through subea tiebacks.

Other Exploration Activities In 2010 we participated in Central Gulf of Mexico Lease Sale 213. We were awarded 11 new deepwater blocks which will complement our growing inventory of exploration opportunities.

International

Our international business focuses on offshore opportunities in multiple countries across the world and provides balance and diversity to our portfolio. Development projects in Equatorial Guinea, Israel, the North Sea, and China have contributed substantially to our growth over the last decade.

Significant recent exploration successes offshore West Africa and Israel have identified multiple major development projects for us that will contribute to production growth in the future. We have large acreage positions in West Africa, the Eastern Mediterranean, and a number of other locations that provide further exploration opportunities.

International operations accounted for 43% of total consolidated sales volumes in 2010 and 55% of total proved reserves at December 31, 2010. International proved reserves are approximately 76% natural gas and 24% crude oil. Operations in Equatorial Guinea and China are conducted in accordance with the terms of PSCs. In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Israel, the North Sea, and other foreign locations are conducted in accordance with concession agreements, permits or licenses.

Sales volumes and estimates of proved reserves for our international operating areas were as follows:

   
Year Ended December 31, 2010
   
December 31, 2010
 
   
Sales Volumes
   
Proved Reserves
 
   
Crude Oil & Condensate
   
Natural Gas
   
NGLs
   
Total
   
Crude Oil, Condensate & NGLs
   
Natural Gas
   
Total
 
   
(MBbl/d)
   
(MMcf/d)
   
(MBbl/d)
   
(MBoe/d)
   
(MMBbls)
   
(Bcf)
   
(MMBoe)
 
International
                                         
Equatorial Guinea
    11       226       -       49       112       869       256  
Israel
    -       130       -       22       2       1,844       310  
North Sea
    10       6       -       11       16       17       19  
Ecuador (1)
    -       25       -       4       -       -       -  
China
    4       -       -       4       10       5       11  
Total International
    25       387       -       90       140       2,735       596  
Equity Investee
    2       -       5       7       -       -       -  
Total
    27       387       5       97       140       2,735       596  
                                                         
Equity Investee Share of Methanol Sales (MMgal)
129                          

(1)
Includes production through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. See Termination of Ecuador PSC.


Wells drilled in 2010 and productive wells at December 31, 2010 in our international operating areas were as follows:

 
Year Ended December 31, 2010
December 31, 2010
 
Gross Wells Drilled or Participated in
Gross Productive Wells
International
         
Equatorial Guinea
5
   
18
 
Israel
3
   
6
 
North Sea
1
   
26
 
China
4
   
20
 
Total International
13
   
70
 

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

Map 3

West Africa (Equatorial Guinea and Cameroon)   West Africa is one of our key operating areas and includes the Alba Field, Block O, and Block I offshore Equatorial Guinea as well as the YoYo mining concession and Tilapia PSC offshore Cameroon. Equatorial Guinea accounted for approximately 24% of 2010 total consolidated sales volumes and 24% of total proved reserves at December 31, 2010. At December 31, 2010, we held approximately 19,000 net developed acres and 233,000 net undeveloped acres in Equatorial Guinea and 563,000 net undeveloped acres in Cameroon.

Alba Field    We have a 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 storage facilities, an LPG processing plant where additional condensate is produced, and a methanol plant capable of producing up to 3,000 metric tons per day gross. The LPG processing plant and the methanol plant are located on Bioko Island.

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, also accounted for by the equity method. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and 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.

Significant development planning has occurred for an Alba field compression project, which is a natural progression for the operations of the field.  We are evaluating certain features of project implementation and expect to grant final project approval in 2011 or 2012.

Aseng Project     Aseng (formerly Benita) is a crude oil development project on Block I (45% operated working interest) which will include five horizontal wells flowing to an 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. We are the technical operator of Aseng.


During 2010, we concluded field drilling of five production wells and three water injection wells and initiated completions.

The FPSO, currently under construction in Singapore, is designed to act as an oil production hub, as well as a liquids storage and offloading hub, with capabilities to support future subsea oil field developments in the area. It will also have the ability to take on board stabilized condensate from gas condensate fields in the area. It will be capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjecting 170 MMcf/d of natural gas. Storage will be approximately 1.6 MMBbls of liquids.

First production at Aseng is currently expected to commence mid-year 2012 with net oil production of approximately 17 MBbl/d.

Alen Project   Alen (formerly Belinda), located primarily on Block O (45% operated average working interest) offshore Equatorial Guinea is our next West Africa development project. Initial field development will include three production wells and three subsea natural gas injection wells tied to a processing facility. Produced condensate will be separated and piped to the Aseng FPSO where it will be held until sold. Associated natural gas will be reinjected into the reservoir to maintain pressure and maximize liquids recovery. The Alen facilities are designed to process 440 MMcf/d of natural gas and 40 MBbl/d of condensate. We are the technical operator of Alen.

We sanctioned the Alen development plan in 2010 and announced the Equatorial Guinean government’s approval of the plan in January 2011. First production at Alen is currently expected to commence by the end of 2013 at 19 MBbl/d, net. Natural gas reinjection is estimated to be 380 MMcf/d during gas-recycling. The total cost of development is estimated at $1.6 billion ($735 million net).

The front-end engineering and design work has been completed, and we are currently negotiating and awarding key project contracts, including the platform facility construction and installation, as well as necessary drilling resources.

Future Oil Projects     We are also evaluating future oil projects at Diega, a 2008 gas condensate and oil discovery on Block I, and Carmen, a 2009 oil discovery on Block O. A Diega/Carmen appraisal well is in the planning stages.

Cameroon   We have an interest in over 1.1 million gross acres offshore Cameroon, which include the YoYo mining concession and Tilapia PSC.  We are the operator (50% working interest) in Cameroon. Natural gas and condensate were discovered in 2007 when we drilled the YoYo-1 exploratory well. During 2010, we acquired a 3-D seismic survey over Yoyo and portions of Tilapia.

Exploration Activities   We are in the midst of a large seismic reprocessing effort involving our existing seismic data on Blocks O and I, integrating new 3-D seismic data for offshore Cameroon and evaluating for future drilling potential offshore West Africa.

Eastern Mediterranean (Israel and Cyprus)   Another key operating area is located in the Eastern Mediterranean. Natural gas sales volumes in Israel accounted for 10% of 2010 total consolidated sales volumes and natural gas reserves accounted for 28% of total proved reserves at December 31, 2010. At December 31, 2010, we held approximately 29,000 net developed acres and 660,000 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 15 licenses, and we are the operator of the properties. We also hold a license covering approximately 795,000 net undeveloped acres offshore Cyprus adjacent to our Israeli acreage.

Mari-B Field    The Mari-B field (47% operated working interest) was the first offshore natural gas production facility in Israel. Natural gas is delivered to a permanent onshore receiving terminal at Ashdod for distribution to purchasers. During 2010 we completed two new wells, allowing us to maintain peak field deliverability of 600 MMcf/d, gross.

Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Our share of the sales volumes has risen from 48 MMcf/d in 2004 to 130 MMcf/d in 2010. Competing imports of natural gas from Egypt to Israel began in 2008. However, during 2010 a higher percentage of the demand for natural gas to produce electricity was met by Mari-B production.

The majority of our natural gas is sold to the Israel Electric Corporation Limited (IEC).  We received record sales prices in 2010 as a result of a new sales contract, signed in 2009, under which certain quantities of gas sold receive a price based on a blend of liquids prices and a producer price index.

We currently expect the Mari-B field to produce until the Tamar field begins producing. The Mari-B field will then be used for natural gas storage. We have signed a letter of intent (LOI) with IEC, under which IEC expects to purchase natural gas to establish a natural gas inventory reserve. The Mari-B partners would provide IEC with injection, storage and withdrawal capabilities for this inventory under a related service agreement.

Tamar Project   We discovered the Tamar natural gas field (36% operated working interest) offshore Israel in the Levantine Basin in 2009. Tamar is one of the world’s largest offshore conventional gas discoveries in recent years.  In 2010, we sanctioned the development plan for Tamar and submitted the plan to the Israeli government for approval.


The initial phase of Tamar development will include five subsea wells. The natural gas produced at these wells will flow to a new offshore platform to be constructed near the existing Mari-B platform. The natural gas will then be delivered to an existing pipeline that connects the Mari-B field to the Ashdod onshore terminal. The development will allow for significant expansion as the Israeli natural gas market grows. We expect to commence field development drilling in the first half of 2011, with first production expected by late 2012 or early 2013.

The Israeli natural gas market continues to grow, and the Tamar partners have signed LOIs to sell natural gas from the Tamar field to several purchasers.

Dalit    Dalit (36% operated working interest) was our second 2009 natural gas discovery in the Levantine Basin. We are currently working with our partners on a cost-effective development plan.

Leviathan   In December 2010, we announced a significant natural gas discovery at the Leviathan prospect (40% operated working interest) in the Levantine Basin offshore Israel. The Leviathan field is the largest discovery in our history and we believe it is the largest deepwater natural gas discovery in the last decade. We are continuing drilling at the Leviathan-1 well in order to evaluate two additional intervals for the existence of crude oil. Results from these deeper tests, which have a low chance of success, are expected during first quarter 2011. As a result of its size, the Leviathan natural gas field will require two or more appraisal wells to further define its boundaries and determine the best development option. See Item 1A. Risk Factors - The magnitude of the Leviathan discovery will present financial and technical challenges for us due to the large-scale development requirements.
 
Other Exploration Activities   We recently completed a 3-D seismic acquisition offshore Israel and, depending on further results from the Leviathan well, expect to drill between two and four exploratory or appraisal wells in the area in 2011. We are also planning a 2-D seismic acquisition for our Cyprus acreage in 2011.

Potential Change in Israel’s Fiscal Regime   See Item 1A. Risk Factors – Our operations may be adversely affected by changes in the fiscal regimes of the countries in which we operate and Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Recent Developments in Israel.

Other International

North Sea   We have been conducting business in the North Sea (the Netherlands and the United Kingdom (UK)) since 1996 and currently have interests in 18 licenses with working interests ranging from 7% to 40%. We are the operator of one block.

Most of our production is from the Dumbarton and Lochranza fields (30% non-operated 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. Dumbarton has eight horizontal producing wells and two water injection wells.  Two additional producing wells from the nearby Lochranza discovery are tied back to the Dumbarton facilities.  During 2010 the Dumbarton field was shut in for approximately two months for facility modifications but has since returned to full production.

We also participate in the Flyndre (22.5% working interest) and Selkirk (30.5% working interest) projects, both located in the UK sector of the North Sea. We are currently working with our partners on development options.

The North Sea accounted for 5% of 2010 total consolidated sales volumes and 2% of total proved reserves at December 31, 2010. At December 31, 2010, we held approximately 7,000 net developed acres and 41,000 net undeveloped acres.

Ecuador   We own and operate the Machala power plant located in Machala, Ecuador. The power plant is fueled by natural gas from the Amistad natural gas field, offshore Ecuador. The government of Ecuador has terminated our PSC for Block 3 offshore Ecuador. See Termination of Ecuador PSC above.

Operations in Ecuador accounted for 2% of 2010 total consolidated sales volumes. Natural gas reserves were an estimated 160 Bcf prior to the termination of our PSC for Block 3. See Item 8. Financial Statements and Supplementary Data – Supplementary Oil and Gas Information (Unaudited).

China     We have been engaged in exploration and development activities in China since 1996 under the terms of a 30-year PSC. 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 2010, we continued expansion of production operations under the modified Supplemental Development Plan (SDP). We set the deck of the B platform, drilled four development wells, two of which are horizontal wells, and one injector well. We also recompleted two existing wellbores to uphole zones, one as an injector and one as a producer.

In 2011, we plan to complete the commissioning of the newly installed B platform and commence engineering and design of a third platform (C platform).  In addition, we plan to drill and complete six development wells, and recomplete two of the existing wells to uphole zones where additional pay has been identified.

China accounted for 2% of 2010 total consolidated sales volumes and 1% of total proved reserves at December 31, 2010. At December 31, 2010, we held approximately 4,000 net developed acres and no undeveloped acres.


Other International Properties   At December 31, 2010, we held undeveloped acreage offshore in other international locations including Nicaragua, India and France. During 2010 we began acquiring 3-D seismic information for Nicaragua and are planning to fund a 2-D seismic survey on the acreage offshore France in the Western Mediterranean Sea in 2011 in return for a working interest in the concession.

Proved Reserves Disclosures

Implementation of the Securities and Exchange Commission’s (SEC) Revisions to Oil and Gas Disclosures   Effective December 31, 2009, we implemented the SEC’s final rules related to the modernization of oil and gas reporting (SEC’s reserves rules). Although the SEC’s reserves rules allow probable and possible reserves to be disclosed separately, we have elected not to disclose probable and possible reserves in this report. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for a description of the most significant revisions to oil and gas reporting disclosures.

Internal Controls Over Reserves Estimates   Our policies regarding internal controls over the recording of reserves estimates require reserves to be in compliance with the SEC definitions and guidance and prepared in accordance with generally accepted petroleum engineering principles. Our internal controls over reserve estimates also include the following:

 
·
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
 
·
each field representing more than 1% of total proved reserves, as well as a rotating group of smaller fields, which combined represent over 80% of our reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and
 
·
NSAI is engaged by and has direct access to the Audit Committee.

In addition, our company-wide short-term incentive plan for 2010 did not include quantitative targets for proved reserves additions.

Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group.

Qualified petroleum engineers in our Houston and Denver 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 (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 NSAI to audit a significant portion of our reserves.  See Third-Party Reserves Audit below.

Technologies Used in Reserves Estimation   The SEC’s updated 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 2010 reserves estimates.

Third-Party Reserves Audit   In each of the years 2010, 2009, and 2008, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2010 included a detailed review of 13 of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 77% of US proved reserves and 97% of international proved reserves (88% of total proved reserves). The reserves audit for 2009 included a detailed review of 20 of our major fields and covered approximately 86% of total proved reserves. The reserves audit for 2008 included a detailed review of 18 of our major fields and covered approximately 86% of total proved reserves.

In connection with the 2010 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 reserves quantities, future producing rates, future net revenue, and the present value of such future net revenue. NSAI also examined our estimates with respect to reserves categorization, using the definitions for proved reserves set forth in Regulation S-X Rule 4-10(a) and subsequent SEC staff interpretations and guidance.

In the conduct of the reserves 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)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2010, 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 99.1 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 the Vice President – Reserves and are reviewed by senior management and the Audit Committee of our Board of Directors. Our practice is to select fields for audit based on size. This selection process results in the audit of each field representing more than 1% of total proved reserves. As a result, for each of the years 2008 – 2010, our 10 largest fields at the current time were audited. The Aseng field was first audited in 2009 and the Tamar and Alen fields were first audited in 2010, as no reserves had been recorded in prior years.

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 12 MMBoe above to 14 MMBoe below as compared with our estimates. On a percentage basis, the NSAI field estimates ranged from 9% above our estimates to 9% 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%. Reserves differences at December 31, 2010 were, in the aggregate, approximately 5 MMBoe, or 0.5%.

Proved Undeveloped Reserves (PUDs)   As of December 31, 2010, our PUDs totaled 182 MMBbls of crude oil, condensate and NGLs and 2,444 Bcf of natural gas, for a total of 590 MMBoe.

PUD Locations     We have several significant ongoing development projects which are in various stages of completion. PUDs are located as follows at December 31, 2010:

 
·
146 MMBoe in the Central DJ Basin, including Wattenberg, where we are projecting reasonable levels of increased activity with projected rig counts in line with past levels of operations;
 
·
20 MMBoe in the deepwater Gulf of Mexico, 91% of which are related to our Galapagos project, which is expected to be producing in late 2011 or early 2012;
 
·
114 MMBoe in Equatorial Guinea, 54% of which are in the Alba field, 23% of which are in the Aseng field and 23% of which are in the Alen field.  The Alba field PUDs represent compression reserves that will be recovered from existing wells and will be reclassified to proved developed during the next five years.  The Aseng and Alen field PUDs are scheduled to be reclassified to proved developed reserves beginning in 2012 and 2013, respectively;
 
·
286 MMBoe (1.7 Tcfe) in the Tamar field, offshore Israel. The Tamar field PUDs are scheduled to be reclassified to proved developed reserves when production begins, currently expected in late 2012 or early 2013; and
 
·
The above fields represent 96% of total PUDs. The remaining 4% are associated with ongoing developments in other US onshore areas and China.

Changes in PUDS    Changes in PUDs that occurred during the year were due to:

 
·
recording of approximately 28 MMBoe PUDS from ongoing onshore US development programs, primarily in Wattenberg;
 
·
recording of approximately 25 MMBoe PUDS acquired in the Central DJ Basin asset acquisition;
 
·
recording of approximately 286 MMBoe PUDs due to the sanction of the Tamar project;
 
·
recording of approximately 27 MMBoe PUDS due to the sanction of the Alen project;
 
·
conversion of approximately 21 MMBoe PUDs into proved developed reserves;
 
·
reclassification of approximately 30 MMBoe PUDs, primarily in Wattenberg, that were not scheduled to be developed within five years from proved to probable reserves;
 
·
negative revision of approximately 7 MMBoe due to a change in the likelihood that the Noa field, offshore Israel, will be pursued for development; and
 
·
positive revisions of approximately 12 MMBoe in PUDs primarily due to changes in commodity prices.

Development Costs    Costs incurred to advance the development of PUDs were approximately $1.1 billion in 2010 (including $266 million non-cash costs related to an increase in our FPSO lease obligation), $440 million in 2009 (including $29 million non-cash costs related to an increase in our FPSO lease obligation), and $528 million in 2008. A significant portion of costs incurred in 2010 related to our major development projects Aseng, Alen, Tamar and Galapagos, which will be converted to proved developed reserves in future years.


Estimated future development costs relating to the development of PUDs are projected to be approximately $1.6 billion in 2011, $1.3 billion in 2012, and $900 million in 2013. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.

Drilling Plans    All PUD drilling locations are scheduled to be drilled prior to the end of 2015.  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 2015.  Initial production from these PUDs is expected to begin during the years 2011 - 2015. All PUDs are scheduled to be developed within 5 years.

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, 2010, no crude oil or natural gas reserves 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 reserves and other information, with the EIA.


Sales Volumes, Price and Cost Data Sales volumes, price and cost data are as follows:

   
Sales Volumes
   
Average Sales Price
   
Average
Production
Cost (1)
 
   
Crude Oil & Condensate
MBbl/d
   
Natural Gas MMcf/d
   
NGLs
MBbl/d
   
Crude Oil & Condensate
Per Bbl
   
Natural Gas
Per Mcf
   
NGLs
Per Bbl
   
Per BOE
 
Year Ended December 31, 2010
                                         
United States
                                         
Wattenberg
    19       151       10     $ 75.11     $ 3.95     $ 43.15     $ 3.62  
Other US
    20       249       4       74.95       4.31       36.23       7.91  
Total US (2)
    39       400       14       75.03       4.17       41.21       5.95  
Alba Field (Equatorial Guinea) (3)
    11       226       -       78.44       0.27       -       2.38  
Mari-B Field (Israel)
    -       130       -       -       4.03       -       1.15  
North Sea
    10       6       -       80.24       5.35       -       11.53  
Ecuador (4)
    -       25       -       -       -       -       -  
China
    4       -       -       75.15       -       -       7.49  
Total Consolidated Operations
    64       787       14       76.46       3.00       41.21     $ 4.93  
Equity Investee (5)
    2       -       5       77.98       -       53.68          
Total
    66       787       19       76.50     $ 3.00     $ 44.90          
Year Ended December 31, 2009
                                                       
United States
                                                       
Wattenberg
    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  
Mari-B Field (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 (5)
    2       -       6       59.51       -       36.03          
Total
    64       781       16     $ 55.87     $ 2.54     $ 31.20          
Year Ended December 31, 2008
                                                       
United States
                                                       
Wattenberg
    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  
Mari-B Field (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 (5)
    2       -       6       96.77       -       58.81          
Total
    71       767       15     $ 82.96     $ 5.04     $ 53.45          

(1)
Average production cost includes oil and gas operating costs and workover and repair expense and excludes production and ad valorem taxes.

(2)
Average crude oil sales prices reflect reductions of $1.32 per Bbl (2010), $2.13 per Bbl (2009), and $22.06 per Bbl (2008) from hedging activities. Average natural gas sales prices reflect a decrease of $0.01 (2010) and an increase of $0.23 per Mcf (2008) from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis. These price increases/reductions resulted from hedge gains/losses that were previously deferred in Accumulated Other Comprehensive Loss (AOCL). All hedge gains/losses relating to US production had been reclassified to revenues by December 31, 2010.

(3)
Average crude oil sales prices reflect reductions of $5.57 per Bbl (2009) and $7.59 per Bbl (2008) from hedging activities. These price reductions resulted from hedge losses that were previously deferred in AOCL. All hedge losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.

Natural gas 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.


(4)
Includes production through November 24, 2010. Our Block 3 PSC was terminated by the Ecuadorian government on November 25, 2010. Intercompany natural gas sales were eliminated for accounting purposes. Electricity sales are included in other revenues. See Termination of Ecuador PSC above.

(5)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.

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, 2010, our operated properties accounted for approximately 64% 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 at December 31, 2010 was as follows:

   
Crude Oil Wells
   
Natural Gas Wells
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
United States
    6,543       5,759.5       6,804       4,968.1       13,347       10,727.6  
Equatorial Guinea
    4       1.6       13       4.4       17       6.0  
Israel
    -       -       6       2.8       6       2.8  
North Sea
    18       3.8       8       1.0       26       4.8  
China
    19       10.8       1       0.6       20       11.4  
Total
    6,584       5,775.7       6,832       4,976.9       13,416       10,752.6  

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. 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, 2010 was as follows:

   
Developed Acreage
   
Undeveloped Acreage
 
   
Gross
   
Net
   
Gross
   
Net
 
(thousands)
                       
United States
                       
Onshore
    1,535       1,012       1,815       1,318  
Offshore
    65       35       562       397  
Total United States
    1,600       1,047       2,377       1,715  
International
                               
Equatorial Guinea
    56       19       573       233  
Cameroon
    -       -       1,125       563  
Israel
    62       29       1,592       660  
North Sea (1)
    52       7       213       41  
China
    7       4       -       -  
Suriname
    -       -       3,087       1,389  
France (2)
    -       -       2,808       2,036  
Nicaragua
    -       -       1,977       1,977  
Cyprus(3)
    -       -       1,136       795  
India
    -       -       694       347  
Total International
    177       59       13,205       8,041  
Total
    1,777       1,106       15,582       9,756  

(1)
The North Sea includes acreage in the UK and the Netherlands.

(2)
We are currently funding a 2-D seismic survey over the acreage in return for a working interest in the concession.
 
(3)
A portion of the acreage has been assigned to a partner and the agreement is awaiting government approval.
 
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.

Future Acreage Expirations   If production is not established or we take no other action to extend the terms of the leases or concessions, undeveloped acreage will expire over the next three years as follows:


   
Year Ended December 31,
 
   
2011
   
2012
   
2013
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
(thousands of acres)
                                   
Onshore US
    177       140       215       142       978       740  
Deepwater Gulf of Mexico
    60       31       46       23       37       23  
Equatorial Guinea
    82       28       -       -       -       -  
Suriname
    1,080       486       2,007       903       -       -  
Total
    1,399       685       2,268       1,068       1,015       763  

Future deepwater Gulf of Mexico lease expirations are reported according to the original lease terms. We are currently unsure of the impact of the Deepwater Moratorium or lack of permit activity on the expiration dates of these leases and if any extensions will be granted.

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
       
   
Productive
   
Dry
   
Total
   
Productive
   
Dry
   
Total
   
Total
 
                                           
Year Ended December 31, 2010
                                         
United States
    4.8       1.9       6.7       510.6       1.0       511.6       518.3  
Equatorial Guinea
    -       -       -       2.0       -       2.0       2.0  
Israel (1)
    0.4       -       0.4       1.0       -       1.0       1.4  
North Sea
    -       -       -       0.6       -       0.6       0.6  
China
    -       -       -       2.3       -       2.3       2.3  
Total
    5.2       1.9       7.1       516.5       1.0       517.5       524.6  
Year Ended December 31, 2009
                                                       
United States (1)
    4.1       1.6       5.7       532.3       2.0       534.3       540.0  
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 (1)
    15.6       2.0       17.6       868.1       44.0       912.1       929.7  
Equatorial Guinea (1)
    1.3       -       1.3       -       -       -       1.3  
North Sea
    -       0.4       0.4       0.6       0.3       0.9       1.3  
Suriname
    -       0.5       0.5       -       -       -       0.5  
Total
    16.9       2.9       19.8       868.7       44.3       913.0       932.8  

(1)
Includes successful exploratory wells drilled but not yet producing.

A productive well is an exploratory, development or extension well that is not a dry well. A dry well (hole) is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

As defined in the rules and regulations of the SEC, an exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir. A development well is part of a development project, which is defined as the means by which petroleum resources are brought to the status of 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 production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

In addition to the wells drilled and completed in 2010 included in the table above, at December 31, 2010, we were in the process of drilling or completing 245 gross (204.5 net) wells onshore US, 2 gross (0.6 net) exploratory wells in the deepwater Gulf of Mexico, 1 gross (0.4 net) development well offshore Equatorial Guinea, and 1 gross (0.4 net) exploratory well offshore Israel.

Domestic Marketing Activities   Crude oil, natural gas, condensate and NGLs produced in the US are generally sold under short-term contracts at market-based prices adjusted for location and quality. Crude oil and condensate are distributed through pipelines and by trucks to gatherers, transportation companies and refineries.

International Marketing Activities   In Equatorial Guinea, natural gas from the Alba Field is sold under a long-term 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. Our share of crude oil and condensate from the Alba Field is sold to Glencore Energy UK Ltd (Glencore Energy) under a short-term sales contract, subject to renewal, and is transported by tanker.


In Israel, we sell natural gas from the Mari-B field under long-term contracts at negotiated prices. IEC is our largest purchaser. In addition, the Tamar partners have signed LOIs to sell natural gas from the Tamar field, which is currently under development, to several purchasers.

Our North Sea crude oil production is transported by tanker and sold on the spot market.

In China, we sell crude oil into the local market under a long-term contract at market-based prices.

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 195 Bcf of natural gas, net to our interest, to various customers in Israel through the year 2022. Approximately 97% 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 Tamar fields in Israel and we do not expect any shortfall. See International – Eastern Mediterranean (Israel and Cyprus).

Significant Purchaser   Glencore Energy was the largest single non-affiliated purchaser of 2010 production and purchased our share of crude oil and condensate production from the Alba field in Equatorial Guinea.  Sales to Glencore Energy accounted for 17% of 2010 crude oil sales, or 11% of 2010 total oil and gas sales. No other single non-affiliated purchaser accounted for 10% or more of oil and gas sales in 2010. 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 2010 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 reduce commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas. For additional information, see Item 1A. Risk Factors – Commodity and interest rate hedging transactions may limit our potential gains and We 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 – Note 10. Derivative Instruments and Hedging Activities.

Termination of Contracts The government of Ecuador terminated our Block 3 PSC on November 25, 2010. See Termination of Ecuador PSC, above, and Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Divestitures.

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 increasing 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 Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) (formerly the Minerals Management Service), 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 Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982 has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;

 
·
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 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; and

 
·
the Department of Transportation, which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater Gulf of Mexico operations.

Other federal agencies with certain authority over our business include the Internal Revenue Service and the SEC, as well as the NYSE upon which shares of our common stock are traded.

On May 17, 2010, the BLM issued a revised oil and gas leasing policy that requires, 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.

The EPA has 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 facilities that emit 25,000 metric tons or more of carbon dioxide equivalent per year to begin collecting greenhouse gas (GHG) emissions data under a new reporting system on January 1, 2010 with the first annual report due March 31, 2011. In November 2010, the EPA issued final regulations requiring the annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production (Subpart W).

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 Wattenberg, and the same Commission’s December 10, 2008 approval of a comprehensive update to statewide rules governing oil and gas operations in Colorado. These rules were reviewed by the Colorado legislature in its 2009 session and became 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 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 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 EPA 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 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 – We are subject to increasing 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

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, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, and individuals. 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

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 exploration, development and production: United States, West Africa, Eastern Mediterranean, North Sea, and Other International and Corporate. See Item 8. Financial Statements and Supplementary Data – Note 18. Segment Information.

Employees

Our total number of employees increased from 1,630 at December 31, 2009 to 1,772 at December 31, 2010. The 2010 year-end employee count includes 185 foreign nationals working as employees in Ecuador, 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, Cyprus 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 would not materially detract 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 PSCs or exploration licenses.

Available Information

Our website address is www.nobleenergyinc.com. Available on this website under “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 under “About Us – Corporate Governance”, 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.


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 and political environment intensifies many of these risks.

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 average settlement price for the prompt month crude oil contract in 2010 ranged from a high of $89.23 per barrel to a low of $74.12 per barrel. The NYMEX monthly settlement price for the prompt month natural gas contract in 2010 ranged from a high of $5.81 per MMBtu to a low of $3.29 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 economic and market conditions, and other factors, including:

 
·
economic factors impacting global gross domestic product growth rates;
 
·
global demand for crude oil and natural gas;
 
·
global factors impacting supply quantities of crude oil and natural gas;
 
·
the potential long-term impact of an abundance of natural gas from shale on the global natural gas supply;
 
·
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 crude oil and natural gas;
 
·
the price and availability of alternative fuels, including coal, nuclear energy, and biofuels;
 
·
the long-term impact of the use of natural gas as an alternative fuel on the crude oil market;
 
·
the availability of pipeline capacity and infrastructure;
 
·
the availability of crude oil transportation and refining capacity;
 
·
weather conditions;
 
·
demand for electricity as well as natural gas used as fuel for electricity generation; and
 
·
domestic and foreign governmental regulations and taxes.

Significant declines in crude oil and natural gas prices for an extended period may have the following effects on our business:

 
·
reducing our revenues, operating income and cash flows;
 
·
reducing the amount of crude oil and natural gas that we can produce economically;
 
·
limiting our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
 
·
limiting our access to sources of capital, such as equity and long-term debt; or
 
·
causing us to delay or postpone some of our capital projects.

In addition, lower commodity prices, including significant declines in the forward commodity price curves, may result in the following:

 
·
asset impairment charges resulting from reductions in the carrying values of our crude oil and/or natural gas properties at the date of assessment, such as occurred in 2008, 2009 and 2010; or
 
·
a reduction in the carrying value of goodwill.

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, some of which will take several years before first production, including Aseng, Alen, Galapagos, Tamar, Gunflint, and others.  Some of these projects, such as oil and gas projects offshore West Africa and Israel, have a great deal of complexity, including extensive subsea tiebacks to an FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. 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 have increased dependency on third-party technology and service providers and other suppliers for these complex projects.  Significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure, could adversely affect development of our projects. We may not be able to compensate for, or fully mitigate, these risks.


Concentration of our operations in a few key areas may increase our risk of production loss.

Our operations are concentrated in four key areas: the Central DJ Basin and the deepwater Gulf of Mexico in the US, offshore West Africa, and the Eastern Mediterranean. These key areas provide most of our current crude oil and natural gas production, each of our major development projects, and most of our exploration potential. In the past several years, we have made several asset divestitures to high-grade and focus our portfolio. Divestitures included non-core, non-strategic assets in the Gulf of Mexico shelf, Mid-Continent and Illinois Basin areas in the US, and Argentina.

As a result of these portfolio changes, our operations and production are concentrated in fewer areas.  Although none of these areas represented more than 25% of our 2010 total consolidated sales volumes, disruption of our business in one of these areas, such as from an accident, natural disaster, government intervention, or other event, would result in a greater impact on our production profile, cash flows and overall business plan than if we operated in a larger number of areas.

We do not maintain business interruption (loss of production) insurance for all of our assets. Loss of production from one of our key operating areas could have a significant negative impact on our cash flows and profitability.

We are subject to increasing 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.

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 government agencies 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.

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 43% of our 2010 total consolidated sales volumes coming from international operations, and will be increasing our exposure through our major development projects offshore Equatorial Guinea and Israel. We are also conducting exploration activities in these and other international areas. Our operations may be adversely affected by political and economic developments, including the following:
 
 
·
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to the proposed changes in Israel’s fiscal regime, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
 
·
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 or termination of contracts, such as the recent termination of our Block 3 PSC by the Ecuadorian government pursuant to Ecuador's new hydrocarbon law;
 
·
disruptions caused by territorial or boundary disputes in certain international regions, including the Eastern Mediterranean, where Lebanon recently made claims related to our projects in Israeli waters;
 
·
changes in drilling or safety regulations in other countries being considered as a result of the Deepwater Horizon Incident, which changes will increase costs and development cycle time;
 
 
·
changes in taxation policies, such as the recent recommendations by a committee established by the Israeli Finance Minister to increase government take, 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 Israel and the UK; and
 
·
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.

Certain of these risks could be intensified by significant new discoveries in the Levantine Basin, where we are currently conducting exploration activities, and other developing basins in the Eastern Mediterranean where there is vast exploration potential remaining and where a large discovery could have a significant impact on the natural gas supply for the nations of Europe and the Eastern Mediterranean region.

Such political and economic developments as mentioned above could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges. In addition, we may not have enough insurance to cover any loss of property resulting from these risks.
 
Our international operations may be adversely affected by war, terrorist acts, or civil disturbances that may occur in regions that encompass our operations.
 
We conduct exploration and development activities in the Eastern Mediterranean and offshore West Africa. These areas have historically been less politically stable than other areas in which we conduct business such as Europe or the US.

In recent weeks, civil unrest, which began in Tunisia and resulted in changes in the Tunisian government, has spread to the Middle East. There have been numerous demonstrations by Egyptian protestors demanding a regime change in their country, and some of the demonstrations have been marked by violence. Recently, the King of Jordan reconstituted his government after protestors demanded economic and political reforms.

Civil unrest could continue to spread throughout the region and involve other areas such as the Gaza Strip or nations such as Syria, Yemen, Lebanon or others. Such unrest, if it continues to spread or grow in intensity, could lead to civil wars; regime changes resulting in governments that are hostile to the US and/or Israel, such as has previously occurred in the region; violations of the 1979 Egypt-Israel Peace Treaty; or regional conflict.

At this time, we are uncertain of the outcome of these events. However, prolonged and/or widespread regional conflict in the Middle East could have the following results, among others:
 
 
·
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
 
·
negative impact on the world crude oil supply if transportation avenues are disrupted, leading to further commodity price volatility;
 
·
capital market reassessment of risk and subsequent redeployment of capital to more stable areas making it more difficult for partners to obtain financing for potential development projects;
 
·
security concerns in Israel, making it more difficult for our personnel or supplies to enter or exit the country;
 
·
reduced market demand in Israel for natural gas due to efforts to conserve domestic resources;
 
·
security concerns leading to evacuation of our personnel;
 
·
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
 
·
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of  gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;
 
·
inability of our service and equipment providers to deliver items necessary for us to conduct  our operations in the Eastern Mediterranean, resulting in delayed start-up of our Tamar project or shut-in of the Mari-B field; and
 
·
lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region.
 
Loss of property and/or interruption of our business plans resulting from hostile acts could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.
 
Our operations may be adversely affected by changes in the fiscal regimes of the countries in which we operate.

Fiscal regimes impact oil and gas companies through laws and regulations governing royalties, taxes or level of government participation in oil and gas projects. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government take, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country.

Governments are currently experiencing fiscal problems triggered by the lingering effects of the global financial crisis, associated recession and current slower economic growth rates. Higher unemployment and slower growth rates, coupled with a reduced tax base, have resulted in reduced government revenues, while government expenditures have increased due to the need for public entitlement or economic stimulus programs. Many countries have generated budget deficits or even approached insolvency and there has been social unrest in many regions.

Due to pressures from local constituents as well as the Organization for Economic Cooperation and Development (OECD) to address these negative fiscal situations and initiate deficit reduction measures, many governments are seeking additional revenue sources, including increases in government take from oil and gas projects.

For example, The US Administration’s fiscal year 2011 budget contained many revenue-raising proposals, including business tax increases, some of which impact oil and gas companies. Notwithstanding the recent extension of reduced tax rates or other favorable energy provisions contained in the Tax Relief Act of 2010, it is likely that some of these proposals will be re-proposed in the fiscal year 2012 budget. It is unclear whether, and to what extent such proposals will pass both houses of Congress and be signed into law. However, it is likely that some of these proposals, such as elimination of certain oil and gas company tax preferences, will receive consideration.

 
25

 
 
In March 2010, the President of the United States signed into law The Patient Protection and Affordable Care Act and The Health Care and Education Reconciliation Act of 2010 (collectively referred to as Health Insurance Reform Legislation) which enacted significant reforms to various aspects of the US health insurance industry including expansion of health care coverage to many uninsured individuals and expansion of coverage to those already insured. Due to its complexity and need for further implementing regulations, the full impact of the Health Insurance Reform Legislation is not yet fully known. However, any future changes in employer funding requirements or tax benefits will likely increase our employee health care costs and reduce our cash flows.

In 2010, the Finance Minister of Israel established an advisory committee to study the country’s fiscal policy as it relates to the upstream oil and natural gas sector, as well as various options, including an increase in royalties or cancellation of tax incentives. In January 2011, the Finance Ministry advisory committee issued its final recommendations which included cancellation of currently-existing tax incentives, including the depletion allowance, and imposition of a special levy ranging from 20% to 50%, on oil and gas profits after a return on investment has been achieved.  At this time we are uncertain of the final outcome of these recommendations, which must be voted on by Israel’s Parliament, and are unable to predict the complete economic impact any change in Israel’s fiscal regime would have on our operations.  A change in Israel’s fiscal regime could reduce the profitability of our Tamar project or a future development project at Leviathan. A retroactive change could reduce the cash flows from our Mari-B project.

In 2010, China began implementing a new price-based energy resource tax on oil and gas extraction in certain of its provinces.

Changes in fiscal regimes have long-term impacts on our business strategy, and uncertainty makes it more difficult to formulate capital investment programs. The implementation of new, or the modification of existing, laws or regulations impacting the amount of government take could disrupt our business plans and negatively impact our operations in the following ways, among others:

 
·
reduce exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
 
·
have a negative impact on the ability of us and/or our partners to obtain project financing;
 
·
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
 
·
reduce the profitability of our projects, resulting in decreases in net income and cash flows;
 
·
result in current projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
 
·
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income;
 
·
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
 
·
adversely affect the price of our common stock.

We have insufficient 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, well 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. Exploration and production activities are also subject to risk from political developments such as war, terrorist acts, civil disturbances, expropriation or nationalization of assets, which can cause loss of or damage to our property.

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 and including such occurrences as well blowouts and resulting oil spills, at a level that balances cost of insurance with our assessment of risk and our ability to achieve a reasonable rate of return on our investments. Although we believe the coverages and amounts of insurance carried are adequate and consistent with industry practice, we do not have insurance protection against all the risks we face, because we chose not to insure certain risks, insurance is not available at a level that balances the cost of insurance and our desired rates of return, or actual losses exceed coverage limits.We regularly review our risks of loss and the cost and availability of insurance and revise our insurance program accordingly.

We expect the future availability and cost of insurance to be impacted by the Deepwater Horizon Incident.  Impacts could include: tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in the Gulf of Mexico and other areas in which we operate, including possible increases in liability caps for claims of damages from oil spills.  We will continue to monitor the legislative and regulatory response to the Incident and its impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.

If an event occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse impact on our financial condition, results of operations and cash flows. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk and Insurance Program.

Our operations in the deepwater Gulf of Mexico, as well as onshore US and international locations, could be adversely affected by future changes in laws and regulations which may occur as a result of the Deepwater Horizon Incident.

The legislative and regulatory response to the Deepwater Horizon Incident is ongoing and may not be limited to the US. In 2010, the US Department of the Interior issued new rules designed to improve drilling and workplace safety, and various Congressional committees began pursuing legislation to regulate drilling activities and increase liability.  In January 2011, the President’s National Commission on the BP Deepwater Horizon Oil Spill and Offshore Drilling released its report, recommending that the federal government require additional regulation and an increase in liability caps. The European Commission has recommended that new legislation be enacted to enhance the safety of offshore oil and gas activities.

Additional regulatory review, slower permitting processes and increased oversight will likely result in longer development cycle time for our deepwater Gulf of Mexico projects. Cycle time is the length of time it takes for a project to progress from first discovery to first production, and longer development cycle times could result in lower rates of return on our investments.

Increased regulation could also have a negative impact on our planned deepwater Gulf of Mexico exploration program. A significant delay or cancellation of planned exploratory activities will reduce our longer term ability to replace reserves, resulting in a negative impact on production over time. To the extent current exploration activities are significantly delayed, a gap could occur in our long-term production profile with a negative impact on our operating results and cash flows.


Additional legislation or regulation is being discussed which could require each company doing business in the Gulf of Mexico to establish and maintain a higher level of financial responsibility under its Certificate of Financial Responsibility (COFR), a certificate required by the Oil Pollution Act of 1990 which evidences a company’s financial ability to pay for cleanup and damages caused by oil spills. There have also been discussions regarding the establishment of a new industry mutual fund in which companies would be required to participate and which would be available to pay for consequential damages arising from an oil spill. These and/or other legislative or regulatory changes could require us to maintain a certain level of financial strength and may reduce our financial flexibility.
 
We are monitoring legislative and regulatory developments; however, the full legislative and regulatory response to the Incident is not yet known.  An expansion of safety and performance regulations or an increase in liability for drilling activities may have one or more of the following impacts on our business:
 
 
·
increase the costs of drilling exploratory and development wells;
 
·
cause delays in, or preclude, the development of our projects in the deepwater Gulf of Mexico or other locations;
 
·
result in higher operating costs;
 
·
divert cash from our capital investments program in order to maintain minimum financial levels or participate in a mandatory industry mutual clean-up fund;
 
·
increase or remove liability caps for claims of damages from oil spills; and
 
·
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
 
Any of the above operating or financial factors may result in a reduction of our cash flows, profitability, and the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in financial responsibility requirements could result in certain of our planned projects becoming uneconomic.
 
Derivatives regulation included in current financial reform legislation could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including a requirement that certain transactions be cleared on exchanges and a requirement to post cash collateral (commonly referred to as “margin”) for such transactions. The Act provides for a potential exception from these clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how this exception applies to particular derivative transactions and the parties to those transactions.  The Act requires the Commodities Futures and Trading Commission (CFTC) to promulgate rules to define these terms. The CFTC is in the process of proposing definitions to determine which entities will face additional requirements for clearing, trading and posting of margin. However, the process is incomplete and we are unsure how these definitions will apply to us.

We use crude oil and natural gas derivative instruments with respect to a portion of our expected production in order to reduce commodity price uncertainty and enhance the predictability of cash flows relating to the marketing of our production and in support of our capital investment program. We use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances. As commodity prices increase or interest rates decrease, our derivative liability positions increase; however, none of our current derivative contracts require the posting of margin or similar cash collateral when there are changes in the underlying commodity prices or interest rates that are referred to in these contracts.

Depending on the rules and definitions adopted by the CFTC, we could be required to post significant amounts of cash collateral with our dealer counterparties for our derivative transactions.  A sudden, unexpected margin call triggered by rising commodity prices or falling interest rates would have an immediate negative impact on our business plan, forcing us to divert capital from exploration, development and production activities. Requirements to post cash collateral could not only cause significant liquidity issues by reducing our flexibility in using our cash and other sources of funds such as our credit facility, but could also cause us to incur additional debt.  In addition, a requirement for our counterparties to post cash collateral would likely result in additional costs being passed on to us, thereby decreasing the effectiveness of our hedges and our profitability.

We face various risks associated with the trend toward increased activism against oil and gas exploration and development activities.

Opposition toward oil and gas drilling and development activity has been growing globally and is particularly pronounced in OECD countries which include the US, the UK and Israel.  Companies in the oil and gas industry, such as us, are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental compliance and business practices.  Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain projects such as offshore drilling or the development of oil shale. For example, environmental activists have recently challenged decisions to grant air-quality permits for offshore drilling and have advocated for increased regulations on shale drilling in the US.

Future activist efforts could result in the following:

 
·
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;
 
·
restrictions on the use of certain operating practices, such as hydraulic fracturing;
 
·
legal challenges or lawsuits;
 
·
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 complying with any resulting new legal or regulatory requirements resulting from these activities that are substantial and not adequately provided for, could have a material adverse effect on our business, financial condition and results of operations.

Slower economic growth rates in the US and other countries in which we operate may materially adversely impact our operating results.

The US and other economies are recovering from a global financial crisis and recession which began in 2008. Growth has resumed, but has been modest and at an unsteady rate.  There are likely to be significant long-term effects resulting from the financial crisis and recession, including a future global economic growth rate that is slower than what was experienced in the years leading up to the crisis, and more volatility may occur before a sustainable, yet lower, growth rate is achieved.

In addition, the OECD has encouraged countries with large federal budget deficits, such as the US, to initiate deficit reduction measures. Such measures, if they are undertaken too rapidly, could further undermine economic recovery and slow growth by reducing demand.

Global economic growth drives demand for energy from all sources, including fossil fuels.  A lower future economic growth rate is likely to result in decreased demand growth for our crude oil and natural gas production. A decrease in demand, excluding changes in other factors, could potentially result in lower commodity prices, which would reduce our cash flows from operations and our profitability.

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 major development projects, such as the Central DJ Basin, Galapagos in the deepwater Gulf of Mexico, Aseng and Alen, offshore Equatorial Guinea, and Tamar, offshore Israel. Significant capital investments on these major development projects are estimated to total approximately $1.1 billion in 2011.  However, first production from the major offshore projects is not expected to occur until Galapagos begins to produce in late 2011 or early 2012.

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 lower production over time. If our cash flows from operations are not sufficient to meet our obligations and fund our capital investment program, 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, our ownership interests in some properties might be reduced or forfeited as a result.

Commodity and interest rate 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 prices fluctuated significantly in 2010. Such volatility challenges our ability to forecast and, as a result, it may become more difficult to manage 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 use interest rate derivative instruments to minimize the impact of interest rate fluctuations associated with anticipated debt issuances. Interest rates are also variable and we may also end up hedging too much or too little when we attempt to effectively fix cash flows related to interest payments on an anticipated debt issuance.

We cannot assure that our hedging transactions will reduce the risk or minimize the effect of volatility in crude oil or natural gas prices or interest rates. See Item 8. Financial Statements and Supplementary Data – Note 10. Derivative Instruments and Hedging Activities.

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 a majority of our large joint venture development projects. As operator of the joint ventures, we pay joint venture expenses and make cash calls on our nonoperating partners for their respective shares of joint venture costs. These projects are capital cost intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs.


In addition, some of our purchasers and joint venture partners are not as creditworthy as we are and may experience credit downgrades or liquidity problems. For example, the international credit rating of IEC, our largest natural gas purchaser in Israel, was recently downgraded. Counterparty liquidity problems could result in a delay in our receiving proceeds from commodity sales or reimbursement of joint venture costs. Credit enhancements have been obtained from some parties in the way of parental guarantees or letters of credit, including our largest 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.

Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a contract. During periods of falling commodity prices, our hedge receivable positions increase, which increases our counterparty exposure. We conduct our hedging activities with a diverse group of highly-rated major banks and market participants and control our level of financial exposure.  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.

We had $1.1 billion in cash and cash equivalents, a majority of which was invested in money market funds and short-term deposits with major financial institutions at December 31, 2010. 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.

We monitor the creditworthiness of our trade creditors, joint venture partners, hedging counterparties and financial institutions on an ongoing basis. However, if one of them were to experience a sudden change in liquidity, it could impair their ability to perform under the terms of our contracts. We are unable to predict sudden changes in creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited and we could incur significant financial losses.

Offshore development involves significant financial risks.

We have ongoing major development projects as well as current or planned exploration activities in the deepwater Gulf of Mexico, offshore West Africa and offshore Eastern Mediterranean. In these areas, there may be limited availability of suitable drilling rigs, drilling equipment, support vessels, and qualified operating personnel. Deepwater drilling rigs are typically subject to long-term contracts. In addition, frontier areas lack the physical and oilfield service infrastructure necessary for production and transportation. As a result, development of an offshore discovery, such as Tamar, Aseng, Alen, or Gunflint, may be a lengthy process and require substantial capital investment.

Difficulty and delays in consistently obtaining drilling rigs and other equipment and services at acceptable rates may lead to project delay, increased costs, and/or inability to forecast production, which could prevent the realization of our targeted return on capital or lead to unexpected future losses.

Due to the current lack of drilling activity in the deepwater Gulf of Mexico caused by the regulatory response to the Deepwater Horizon Incident, drilling, equipment and oilfield services companies may decide to exit the Gulf of Mexico making such services even less available and/or more expensive once drilling activities are allowed to resume.

We may be unable to make attractive acquisitions, successfully 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 Central DJ Basin asset acquisition in 2010.  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 an additional 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 maintain an ongoing portfolio management program which includes sales of non-core, non-strategic assets, such as the sales of non-core onshore US assets in 2010 and our interest in Argentina in 2008. These transactions can also result in changes in operations, systems, or management and other personnel.

Organizational modifications due to acquisitions, divestitures or other portfolio management actions, 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 challenges can be dealt with successfully, 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 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. In accordance with the SEC’s revisions to rules for oil and gas reserves reporting, which we implemented effective December 31, 2009, our reserves estimates are based on 12-month average prices; therefore, reserves quantities will change when actual prices increase or decrease. The reserves 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 revisions to oil and gas company reserves reporting requirements;
 
·
assumptions concerning future crude oil and natural gas prices;
 
·
anticipated development cycle time;
 
·
future development costs;
 
·
future operating costs;
 
·
severance and excise taxes; 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 petroleum engineers or by the same petroleum engineers but at different times may vary substantially. Accordingly, reserves estimates may be subject to positive or negative revisions, and actual production, revenue and expenditures with respect to our reserves likely will vary, possibly materially, from estimates.

Additionally, because some of our reserves 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.

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:

 
·
injuries and/or deaths of employees, supplier personnel, or other individuals;
 
·
pipeline ruptures and spills;
 
·
fires;
 
·
explosions, blowouts and well cratering;
 
·
equipment malfunctions;
 
·
formations with abnormal pressures;
 
·
release of pollutants;
 
·
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.

Exploratory drilling may not result in the discovery of commercially productive reservoirs.

We depend on exploration success to provide growth in production and reserves and are planning an active exploratory drilling program in 2011. Exploratory drilling requires significant capital investment and is not always successful. For example, we incurred dry hole expense in 2010 because the Double Mountain exploratory well in the deepwater Gulf of Mexico found noncommercial quantities of hydrocarbons.

Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations 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.

Exploratory drilling activities may be curtailed, delayed or canceled, resulting in significant exploration expense, as a result of a variety of factors, including:

 
·
title problems;
 
·
compliance with environmental and other governmental requirements;


 
·
increases in the cost of, or shortages or delays in the availability of, drilling rigs, equipment and qualified personnel;
 
·
unexpected drilling conditions;
 
·
pressure or other irregularities in formations;
 
·
equipment failures or accidents; and
 
·
adverse weather conditions.

In addition, companies seeking new reserves often face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, and often need to develop or invest in new technologies. This increases cost as well as drilling risk.

For certain capital-intensive deepwater Gulf of Mexico or international projects, it may take several years to evaluate the future potential of an exploration well and make a determination of its economic viability, resulting in delays in cash flows from production start-up and a lower return on our investment.

Due to our level of planned exploration activity, future dry hole cost could be significant and have a negative impact on our results of operations and cash flows.

Development drilling may not result in commercially productive quantities of oil and gas reserves.

Our exploration success has provided us with a number of major development projects on which we are moving forward. We depend on these projects to provide long life, sustained cash flows after investment and attractive financial returns. However, development drilling is not always successful and the profitability of development projects may change over time.

For example, in new development areas such as Gunflint or Tamar, available data may not allow us to completely know the extent of the reservoir or choose the best locations for drilling development wells. Therefore, a development well we drill may be a dry hole or result in noncommercial quantities of hydrocarbons. Projects in frontier areas may require the development of special technology for development drilling or well completion and we may not have the knowledge or expertise in applying new technology. Our efforts may result in a dry hole or a well that finds noncommercial quantities of hydrocarbons. Development drilling has the same legal and physical risks as exploratory drilling, described above, which can result in the drilling of a development dry hole or the incurrence of substantial development costs without a corresponding increase in proved reserves.

All costs of development drilling and other development activities are capitalized, even if the activities do not result in commercially productive quantities of oil and gas.  This puts a property at higher risk for future impairment if commodity prices decrease or operating or development costs increase.

Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficulties or delays in completing development wells.  For example, in areas of high activity and demand in which we concentrate, such as the Rocky Mountains, we may experience delays in obtaining well completion rigs and services. Frontier areas may not have adequate infrastructure for gathering, processing or transportation, and production may be delayed until they are constructed. This results in a decrease in current cash flows and reduces the return on our investment.

Costs of drilling, completing and operating wells are often uncertain, and cost factors can adversely affect the economics of a project. Even a development project with significant reserves that is currently economic can become uneconomic in the future if commodity prices decrease or operating or development costs increase, resulting in impairment charges and a negative impact on our results of operations.

The magnitude of the Leviathan discovery will present financial and technical challenges for us due to the large-scale development requirements.

In December 2010, we announced a significant natural gas discovery at the Leviathan prospect, offshore Israel. The Leviathan field is the largest discovery in our history and we believe it is the largest deepwater natural gas discovery in the last decade. As a result of the combined discoveries of Tamar and Leviathan, Israel now faces a potential surplus of natural gas.

Development options for Leviathan include export of surplus natural gas to Europe or Asia through development of LNG terminals or underwater pipelines. Each of these development options would require a multi-billion dollar investment and take several years to complete. We have a nearly 40% working interest in Leviathan. As a result, we will likely seek partners to provide technical and financial support as well as midstream and downstream expertise.

In addition, we must resolve with the Israeli government Leviathan’s treatment as a result of the proposed changes in Israel’s fiscal regime, discussed above, that could potentially reduce the anticipated profitability of the project.

Failure to execute a successful development scenario for Leviathan could result in damage to our reputation, limitations on our growth and negative effects on our operating results.

The unavailability or high cost of drilling rigs, equipment, supplies, other oil field services and personnel 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 and oilfield services. There may also be a shortage of trained and experienced personnel. During these periods, the costs of such items 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, deepwater Gulf of Mexico, prior to the Deepwater Moratorium, and in some international locations that typically have limited availability of equipment and personnel, such as West Africa and the Eastern Mediterranean.


During periods of increasing levels of industry exploration and production, such as we currently are experiencing in the Rocky Mountains Niobrara formation, the demand for, and cost of, drilling rigs and oilfield services increases. In addition, regulatory changes in response to the Deepwater Horizon Incident may also result in higher costs for these rigs and services. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Contractual Obligations for additional information on drilling rig contracts.

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:

 
·
large multi-national, integrated oil companies;
 
·
state-controlled national oil companies;
 
·
US independent oil and gas companies;
 
·
service companies engaging in exploration and production activities; and
 
·
private oil and gas equity funds.

We face competition 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.

Many of our competitors have financial and other resources substantially in excess of those available to us. 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. This highly competitive environment could have an adverse impact on our business.

Indebtedness may limit our liquidity and financial flexibility.

As of December 31, 2010, we had long-term indebtedness of $2.3 billion (including an FPSO lease obligation of $295 million), with $350 million drawn under our bank credit facility. Our indebtedness represented 25% of our total book capitalization at December 31, 2010.

 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;
 
·
a covenant contained in our revolving credit facility provides that our total debt to capitalization ratio (as defined) will not exceed 60% at any time, which  may limit our ability to borrow additional funds, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and in our industry;
 
·
a covenant contained in our revolving credit facility restricts the payment of dividends on our common stock if, after giving effect thereto, an Event of Default shall have occurred and be continuing or been caused thereby;
 
·
additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants;
 
·
changes in the credit ratings of our debt may negatively affect the cost, terms, conditions and/or 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. A higher level of indebtedness increases the risk that our liquidity may deteriorate and we default on our debt obligations. Our ability to meet our debt obligations and service our debt 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. See Item 8. Financial Statements and Supplementary Data – Note 12. Long-Term Debt.


The marketability of our Rocky Mountain and deepwater 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 firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical or other reasons, including adverse weather conditions, such as occurred when our deepwater Gulf of Mexico Ticonderoga development became shut in as a result of hurricane damage to third party processing and pipeline facilities in 2008.

Third-party systems and facilities 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 delay production, thereby harming our business and, in turn, our financial condition, results of operations and cash flows.

Our operations and investment in the Machala power plant in Ecuador have been adversely affected by the Ecuadorian government’s termination of our PSC for Block 3.

A newly enacted hydrocarbon law in Ecuador aims to change current production-sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010. It also allows the Ecuadorian government to nationalize oil and gas fields if a private operator does not comply with local laws.

A service contract on Block 3 (100% working interest) was not negotiated, and the government of Ecuador terminated the Block 3 PSC with our subsidiary, EDC Ecuador Ltd. on November 25, 2010.  We are continuing to work with the government of Ecuador to resolve this matter. However, we are uncertain as to the potential outcome of this matter, resolution of which could ultimately lead to a reduction in the value of the receivable or our investments in Ecuador which, as of December 31, 2010, had a net book value of approximately $66 million.

Our operations require us to comply with a number of US and international laws and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business.

Our operations require us to comply with a number of US and international laws and regulations, including those involving anti-corruption. For example, the US Foreign Corrupt Practices Act (FCPA) and similar laws and regulations enacted or promulgated by countries pursuant to the 1997 Organization for Economic Co-operation and Development Anti-Bribery Convention generally prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. The scope and enforcement of anti-corruption laws and regulations may vary. The recently-enacted UK Bribery Act of 2010, which was originally scheduled to become effective in April 2011, is broader in scope than the FCPA and applies to public and private sector corruption and contains no facilitating payments exception. Violations of such laws or regulations could result in substantial civil or criminal fines or sanctions. Actual or alleged violations could damage our reputation, be expensive to defend, and impair our ability to do business.

We have merged with or acquired other companies in the past. Mergers of businesses often require the approval of certain government or regulatory agencies and such approval could contain terms, conditions, or restrictions that would be detrimental to our business after a merger. US anti-trust laws require waiting periods and even after completion of a merger, governmental authorities could seek to block or challenge a merger as they deem necessary or desirable in the public interest. Prevention of a merger by anti-trust laws could impair our ability to do business.

Increased regulation of business practices could result in higher operating costs.

The current trend is toward increased regulation of business practices and additional reporting requirements. For example the EPA issued the Final Mandatory Reporting of Greenhouse Gases Rule. We are subject to these new reporting requirements Under Subpart W, Petroleum and Natural Gas Systems. Compliance with these and other new rules results in additional effort on the part of our personnel. In addition, other legislation may be enacted in order to restrict GHG emissions in the US or regulate hydraulic fracturing under the Safe Drinking Water Act.

The Dodd-Frank Act requires both the CFTC and the SEC to enact numerous rules and regulations, some of which could impact our business practices and negatively affect our financial flexibility or place additional reporting burdens on us.

Although it is not possible at this time to predict the final outcome of these rule-making and standard-setting efforts, it is likely that the magnitude of these changes will require an unprecedented compliance effort on our part, could divert management’s attention, and may require significant expenditures, as well as place additional burden on our internal financial controls.

We operate in a litigious environment.

We operate in the US and other countries which have proven to be unusually litigious environments. Most oil and gas companies, such as us, are involved in various legal proceedings, such as title, royalty or contractual disputes, in the ordinary course of business. We defend ourselves vigorously in all such matters.


Because we maintain a diversified portfolio that is balanced between US and international projects, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. If we are not able to successfully defend ourselves, there could be a delay or even halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows. Legal proceedings could result in a substantial liability. In addition, legal proceedings distract management and other personnel from their primary responsibilities.

A change in US energy policy can have a significant impact on our operations and profitability.

US energy policy and laws and regulations could change quickly.  Currently, substantial uncertainty exists about the nature of potential rules and regulations that could impact the sources and uses of energy in the US.  We design our exploration and development strategy and related capital investment programs years in advance. As a result, we are hindered in our ability to plan, invest and respond to potential changes in our business. This can result in a reduction of our cash flows and profitability to the extent we are unable to respond to sudden or significant changes in our operating environment due to changes in US energy policy.

The adoption of GHG emission or other environmental 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 recent years, each house of Congress has considered legislation to address GHG emissions, such as the American Clean Energy and Security Act of 2009, also known as the Waxman-Markey Bill, passed by the House of Representatives, and The Clean Energy Jobs and American Power Act, or the Boxer-Kerry Bill, introduced to the Senate. Future legislation could include mandatory carbon dioxide emissions goals, measures to encourage use of renewable energy over fossil-based fuels, higher penalties and fines for violations of various environmental laws, or other regulations designed to curb GHG emissions.

One measure considered frequently has been the establishment of a “cap and trade” system for restricting GHG emissions in the US. Under such system, certain sources of GHG emissions would be required to obtain GHG emission “allowances” corresponding to their annual emissions of GHGs. The number of emission allowances issued each year would decline as necessary to meet overall emission reduction goals. As the number of GHG emission allowances declines each year, the cost or value of allowances is expected to escalate significantly.

The EPA has issued GHG 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 GHG pollution threatens the public health and welfare of current and future generations.  The EPA has issued final regulations requiring petroleum and natural gas operators meeting a certain emissions threshold to report their GHG emissions to the EPA (Subpart W). The EPA has indicated that it will use data collected through the reporting rules to decide whether to promulgate future GHG limits.

Since approximately 61% of our total 2010 crude oil and NGL production and 51% of our total 2010 natural gas production derive from the US, any laws or regulations that may be adopted to restrict or reduce emissions of US GHGs could require us to incur higher operating costs, increase our development cycle time, and have an adverse effect on demand for the crude oil and natural gas we produce. In addition, we could be required to make significant capital expenditures to comply with new environmental legislation, which would cause us to divert capital from exploration, development and production activities.

Federal or state hydraulic fracturing legislation could increase our costs and restrict our access to oil and gas reserves.

Hydraulic fracturing involves the injection of a mixture, comprised primarily of water and sand, and a small amount of chemicals, under pressure into rock formations to stimulate production. We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs, including Wattenberg, which represented 25% of our 2010 consolidated sales volumes.

Hydraulic fracturing using fluids other than diesel is currently exempt from regulation under the federal Safe Drinking Water Act, but opponents of hydraulic fracturing have called for further study of the technique’s environmental effects and, in some cases, a moratorium on the use of the technique. Several proposals have been submitted to Congress that, if implemented, would subject all hydraulic fracturing to regulation under the Safe Drinking Water Act. Further, the EPA’s Office of Research and Development (ORD) is conducting a scientific study to investigate the possible relationships between hydraulic fracturing and drinking water. The ORD expects to initiate the study in 2011 and have the initial study results available by late 2012.

In addition, some states have taken actions concerning hydraulic fracturing.  In October 2010, the Governor of Pennsylvania issued a moratorium on new natural gas development on state forest lands.  The New York Legislature passed a bill imposing a moratorium on issuance of new permits for the drilling of wells that use hydraulic fracturing for the purpose of stimulating natural gas or oil in the Marcellus Shale formation, but the Governor of New York subsequently vetoed the bill. On December 13, 2010, however, the Governor of New York issued Executive Order No. 41, which prohibits issuance of state permits for high-volume hydraulic fracturing combined with horizontal drilling until the New York Department of Environmental Conservation completes its Final Supplemental Generic Environmental Impact Statement (SGEIS). Under the order, the New York Department of Environmental Conservation must publish a revised draft SGEIS on or about June 1, 2011 and allow a public comment period of at least 30 days. Accordingly, this moratorium is expected to last until at least July 1, 2011. Other states could take similar action.


Several states have considered, or are considering, legislation or regulations that would require disclosure of chemicals used for hydraulic fracturing. In June 2010, the Wyoming Oil and Gas Conservation Commission passed a rule requiring disclosure of hydraulic fracturing fluid content.  In November 2010, the Pennsylvania Environmental Quality Board proposed regulations that would require reporting of the chemicals used in fracturing fluids.

Although it is not possible at this time to predict the final outcome of the ORD’s study or the requirements of any additional federal or state legislation or regulation regarding hydraulic fracturing, any new federal or state 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 develop oil and gas reserves.

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 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 shareholders.

Disclosure Regarding Forward-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 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,” “target,” “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.

Item 1B.
Unresolved Staff Comments

None.
 
 Item 3.
Legal Proceedings

We are involved in various 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 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.
[Removed and Reserved]


Executive Officers

The following table sets forth certain information, as of February 10, 2011, with respect to our executive officers.

Name
 
Age
 
Position
         
Charles D. Davidson (1)
 
60
 
Chairman of the Board, Chief Executive Officer and Director
         
David L. Stover (2)
 
53
 
President, Chief Operating Officer
         
Kenneth M. Fisher (3)
 
49
 
Senior Vice President, Chief Financial Officer
         
Ted D. Brown (4)
 
55
 
Senior Vice President, Northern Region
         
Rodney D. Cook (5)