Noble Energy Inc.
NOBLE ENERGY INC (Form: 10-K, Received: 02/09/2012 11:48:39)


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

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2011
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
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. x Yes o No
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. o Yes x No
 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. x Yes o No
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). x Yes o No
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
 
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). o Yes x No

Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2011: $15.6 billion.
Number of shares of Common Stock outstanding as of January 13, 2012: 176,958,537.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2012 Annual Meeting of Stockholders to be held on April 24, 2012, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2011, are incorporated by reference into Part III.
 


 
 

 
 
T AB LE OF CONTENTS

PART I
Items 1. and 2.
3
Item 1A.
29
Item 1B.
46
Item 3.
46
Item 4.
46
 
47
PART II
Item 5.
49
Item 6.
51
Item 7.
52
Item 7A.
83
Item 8.
84
Item 9.
136
Item 9A.
136
Item 9B.
136
PART III
Item 10.
137
Item 11.
137
Item 12.
137
Item 13.
137
Item 14.
137
PART IV
Item 15.
137

 
 

 
GLOSSARY
 
In this report, the following abbreviations are used:
 
Bbl
 
Barrel
BBoe
 
Billion barrels oil equivalent
Bcf
 
Billion cubic feet
BOE
 
Barrels 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 commodity price disparities, the price for a barrel of oil equivalent for natural gas is significantly less than the price for a barrel of oil.
Boe/d
 
Barrels oil equivalent per day
Btu
 
British thermal unit
FPSO
 
Floating production, storage and offloading vessel
HH
 
Henry Hub Index
LNG
 
Liquefied natural gas
LPG
 
Liquefied petroleum gas
MBbl/d
 
Thousand barrels per day
MBbls
 
Thousand barrels
MBoe
 
Thousand barrels oil equivalent
MBoe/d
 
Thousand barrels oil equivalent per day
Mcf
 
Thousand cubic feet
Mcfe
 
Thousand cubic feet equivalent
MMBbls
 
Million barrels
MMBoe
 
Million barrels oil equivalent
MMBtu
 
Million British thermal units
MMcf
 
Million cubic feet
MMcf/d
 
Million cubic feet per day
MMcfe
 
Million cubic feet equivalent
MMcfe/d
 
Million cubic feet equivalent per day
MMgal
 
Million gallons
NGL
 
Natural gas liquids
PSC
 
Production sharing contract
Tcfe
 
Trillion cubic feet equivalent
US GAAP
 
United States generally accepted accounting principles
WTI
 
West Texas Intermediate Index
 
 
2

 
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. All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated.
 
Our aim is to achieve growth in value 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 the US and in international locations such as West Africa and the Eastern Mediterranean, has resulted in a visible lineup of major development projects which positions us for substantial future reserves, production and cash flow growth. Occasional strategic acquisitions of producing and non-producing properties, such as our entry into a new core area in 2011, the Marcellus Shale, and the Denver-Julesberg (DJ) Basin asset acquisition in 2010, combined with the periodic 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. The first of our major development projects, Aseng, offshore Equatorial Guinea, began commercial crude oil production in November 2011, coming online earlier than scheduled and 13% under budget. 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. Our portfolio offers a diverse production mix among crude oil, US natural gas, and international natural gas.
 
We have operations in five core areas:
 
 
·
the DJ Basin (onshore US);
 
·
the Marcellus Shale (onshore US);
 
·
the deepwater Gulf of Mexico (offshore US);
 
·
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 sufficient liquidity levels. See Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2007-2011.
 
Major Development Project Inventory    We are moving forward on a number of major development projects, many of which have resulted from our exploration success. Each project will flow through the various development phases including appraisal drilling, front-end engineering and design, infrastructure build-out and exploitation. We currently have projects spanning all phases of the development cycle with some contributing production in 2011 and others with first production targets ranging from 2012 through 2016 and beyond. 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 resulting from exploration success and strategic acquisitions include the following:
 
Sanctioned Projects
Unsanctioned Projects
       
·
Horizontal Niobrara (onshore US);
·
Gunflint (deepwater Gulf of Mexico);
·
Marcellus Shale (onshore US);
·
Leviathan (offshore Israel);
·
Galapagos (deepwater Gulf of Mexico);
·
Diega (offshore Equatorial Guinea); and
·
Tamar (offshore Israel);
·
West Africa gas project (offshore Equatorial Guinea).
·
Aseng (offshore Equatorial Guinea); and
·
Alen (offshore Equatorial Guinea).
 
Additionally, in December 2011, we announced our natural gas discovery well (A-1) in Block 12, offshore Cyprus.
 
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, 2011 were as follows:
 
Summary of Oil and Gas Reserves as of Fiscal-Year End
Based on Average Fiscal-Year Prices
 
   
December 31, 2011
 
   
Proved Reserves
 
   
Crude Oil,
Condensate
& NGLs
   
Natural Gas
   
Total (1)
 
Reserves Category
 
(MMBbls)
   
(Bcf)
   
(MMBoe)
 
                   
Proved Developed
                 
United States
    134       1,195       333  
Equatorial Guinea
    60       497       143  
Israel
    -       83       14  
Other International (2)
    13       11       14  
Total Proved Developed Reserves
    207       1,786       504  
Proved Undeveloped
                       
United States
    110       781       240  
Equatorial Guinea
    46       289       94  
Israel
    3       2,186       368  
Other International (2)
    3       1       3  
Total Proved Undeveloped Reserves
    162       3,257       705  
Total Proved Reserves
    369       5,043       1,209  
 
(1)
  Natural gas is converted on the basis of six Mcf of gas per one Bbl 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 2011 were approximately 1.2 BBoe, an 11% increase from 2010. US reserves accounted for 47% of the total, and international reserves accounted for 53%. Our 2011 reserves mix is 31% global liquids, 42% international natural gas, and 27% US natural gas.
 
See Proved Reserves Disclosures, below, and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited) for further discussion of proved reserves.
 
Crude Oil and Natural Gas Properties and Activities    We search for crude oil and natural gas properties onshore and offshore, and seek to acquire exploration rights and conduct exploration activities in areas of interest. These activities include geophysical and geological evaluation and exploratory drilling, where appropriate. 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 advantages, such as proprietary seismic data and operational expertise, and which we believe generate superior returns. We have had substantial exploration success onshore US and in the deepwater Gulf of Mexico, the Douala Basin offshore West Africa and the Levant Basin offshore Eastern Mediterranean, resulting in a significant portfolio of major development projects. 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 and strategic acquisitions have provided us with numerous development opportunities, as demonstrated in our growing inventory of major development projects.  In 2011, we commenced oil production from Aseng, the first of our major development projects, seven months ahead of the original schedule and 13% under budget. Additionally, we continued to make significant progress on our other major development 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 periodically divest non-core, non-strategic assets in order to optimize our asset portfolio.
 
 
Entry into Marcellus Shale Joint Venture     On September 30, 2011, we entered into an agreement with a subsidiary of CONSOL Energy Inc. (CONSOL) to jointly develop oil and gas assets in the Marcellus Shale areas of southwest Pennsylvania and northwest West Virginia. The Marcellus Shale Joint Venture strengthens and rebalances our portfolio, providing a new, material growth area, which we believe will contribute to future reserves, production, and cash flows.  This transaction complements and further strengthens our US portfolio by adding a high-quality asset with substantial growth potential close to the US’s largest gas market, the Northeast US. It significantly increases our inventory of low risk, repeatable projects while exposing us to more US unconventional resources. The Marcellus Shale Joint Venture, combined with our other domestic projects in the DJ Basin and the deepwater Gulf of Mexico, provides balance to our rapidly expanding international programs.
 
Under the terms of the CONSOL agreement, we acquired 50% interests in approximately 628,000 net undeveloped acres, existing Marcellus Shale production and existing infrastructure for approximately $1.3 billion, including post-closing adjustments. Payments will be made in three annual installments, with the first installment made at closing on September 30, 2011.  We will pay an additional $2.1 billion in the form of a carry of CONSOL’s drilling and completion costs. The carry, which we expect to extend over approximately eight years or more, is capped at $400 million annually and suspended if average Henry Hub natural gas prices fall and remain below $4.00 per MMBtu for three consecutive months. The carry terms ensure economic alignment with our partner in periods of low natural gas prices. Initially, we will be the designated operator of the wet-gas areas (areas with more condensate or liquids) and CONSOL will be the designated operator of the dry-gas areas (areas with little or no condensate or liquids).
 
As a result of this transaction, we are now focusing on three core areas within the US: the DJ Basin, the Marcellus Shale, and the deepwater Gulf of Mexico.  We are also considering the divestiture of certain non-core onshore US properties from our portfolio.
 
See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources and Item 8. Financial Statements and Supplementary Data – Note 3. Acquisitions and Divestitures and Note 12. Long-Term Debt.
 
Exit from Ecuador   In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. The Ecuadorian government had previously terminated our Block 3 PSC (100% working interest) on November 23, 2010, as we had not negotiated a service contract on Block 3 in accordance with the terms of a newly-enacted hydrocarbon law. The law aimed to change existing production sharing arrangements into service contracts and provided for renegotiation of certain contracts by November 23, 2010. We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets, onshore gas processing facilities, and Block 3 PSC and the assignment of the Machala Power electricity concession and its associated assets. Our net book value for the assets had been reduced due to previous impairment charges, resulting in a pre-tax gain of $25 million.
 
DJ Basin Asset Acquisition   In March 2010, we acquired substantially all of the US Rocky Mountain oil and gas 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 DJ Basin, one of our core 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 provides significant growth potential. Included in the purchase were approximately 323,000 total net acres.
 
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.
 
Asset Impairments   During 2011, we recorded impairment charges of $759 million mainly related to our non-core onshore US assets.  The majority of these impairment charges were triggered by the significant decline, approximately 17% over a five year future period, in natural gas prices in the fourth quarter of 2011. The US natural gas price environment continued to be volatile during 2011 as spot prices declined 32% from $4.41 per MMBtu at December 31, 2010 to $2.99 MMBtu at December 31, 2011.  See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.
 
 
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 54% of our 2011 total consolidated sales volumes and 47% of total proved reserves at December 31, 2011. Approximately 57% of the proved reserves are natural gas and 43% 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, 2011
   
December 31, 2011
 
   
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
    23       166       11       62       191       871       337  
Marcellus Shale
    -       19       -       3       -       542       90  
Rocky Mountain/Mid-Continent
    3       149       2       30       22       464       99  
Deepwater Gulf of Mexico
    10       20       1       15       21       24       25  
Gulf Coast and Other
    2       34       1       7       10       75       22  
Total
    38       388       15       117       244       1,976       573  
 
Wells drilled in 2011 and productive wells at December 31, 2011 for our US operating areas were as follows:
 
      Year Ended
December 31, 2011
      December 31, 2011  
      Gross Wells Drilled
or Participated in
     
Gross Productive
Wells
 
Wattenberg
   
663
     
8,415
 
Marcellus Shale
   
23
     
102
 
Rocky Mountain/Mid-Continent
   
157
     
5,120
 
Deepwater Gulf of Mexico
   
1
     
7
 
Gulf Coast and Other
   
11
     
490
 
Total
   
855
     
14,134
 
 
Locations of our onshore US operations as of December 31, 2011 are shown on the map below:

IMAGE 1
 
DJ Basin / Wattenberg   One of our core operating areas is the DJ Basin, where we have a significant acreage position of over 860,000 net acres. Included in the DJ Basin is Wattenberg (approximately 96%   operated working interest), our largest onshore US asset, where we have a multi-year project inventory. In 2011, we continued to improve our operational performance while accelerating our drilling activities. During 2011 we had record sales volumes from our horizontal drilling program that began in 2010 and targets the Niobrara formation.
 
 
Wattenberg includes:
 
 
·
our historical Wattenberg development area, where we have conducted substantial vertical development over the last several years as well as successful horizontal drilling in this high density area;
 
·
the northern and eastern edges of our historical Wattenberg development area where we are focusing on expanding the economic limits of the field, as expansion of this area has resulted in increases in our crude oil and NGL production volumes and 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 where we began drilling horizontal wells in 2010.
 
During 2011, we drilled a total of 639 successful development wells in historical Wattenberg, of which, 64 were drilled horizontally into the Niobrara formation. In 2011, we began constructing multi-well horizontal drilling pads and centralized production facilities to minimize our surface use and allow for more efficient execution and operations.  We are currently evaluating the viability of 80-acre horizontal well spacing and extended reach horizontal lateral wells.
 
Wattenberg contributed 62 MBoe/d of sales volumes and represented approximately 29% of total consolidated sales volumes in 2011, with approximately 55% being liquids, and approximately 337 MMBoe or 28% of total proved reserves at December 31, 2011. Horizontal drilling in the Niobrara has significantly expanded the economic limits of this field. Of the net sales volumes from Wattenberg, approximately 8 MBoe/d came from a total of 85 producing wells in our horizontal Niobrara program. We also drilled eight horizontal wells in the Niobrara formation in northern Colorado.
 
Our 2011 Wattenberg drilling program resulted in additions to proved reserves of approximately 67 MMBoe, approximately 63% of which are liquids.
 
We have also started a horizontal drilling program on additional acreage in southeastern Wyoming and we are evaluating processing and transportation infrastructure needs as well as optimum well completion techniques.
 
At year-end, we were running eight vertical rigs, five horizontal rigs and 21 completion units in the DJ Basin. We expect to add three to four horizontal rigs and drill approximately 170 horizontal operated and 280 vertical operated wells in the DJ Basin in 2012.  Within the next two years, we intend to double our annualized horizontal rig count and well completions.
 
Marcellus Shale    In September of 2011, we entered into a new core operating area, the Marcellus Shale, through a joint venture with CONSOL. During the fourth quarter of 2011, the Marcellus Shale was producing approximately 74 MMcf/d, net to us, compared to net production of 50 MMcf/d at the end of the third quarter of 2011.  This represents significant growth at a pace that is faster than we had originally modeled in our acquisition economics.   At December 31, 2011, net proved gas reserves were approximately 542 Bcf.
 
At year-end CONSOL was operating five horizontal rigs and one completion unit on our joint acreage in the Marcellus Shale. In January 2012 we began operating our first horizontal rig in conjunction with the opening of our new field office in Canonsburg, Pennsylvania.  CONSOL’s expertise in permitting, local water sourcing, transportation and processing will help facilitate our growth in operations. During the remainder of 2012, we expect to add approximately two horizontal rigs in the wet-gas area of the Marcellus Shale which complements our previous experience in the liquids-rich development in the DJ Basin.  We have executed a multi-year development plan with CONSOL that steadily increases the rig count through 2016, and we estimate during 2012 the joint venture will operate six horizontal rigs.
 
Our joint development plan for 2012 projects that CONSOL will drill approximately 60 horizontal wells in the dry-gas areas of the Marcellus Shale and that we will drill approximately 39 horizontal wells focused in the wet-gas areas of the Marcellus Shale. Our dry-gas program delivers economically attractive returns even in low natural gas price environments due to strong production performance, competitive costs, and access to the US's largest gas market, the Northeast US.
 
Since the joint venture agreement was finalized on September 30, 2011, CONSOL has drilled a total of 23 successful development wells on our joint acreage.  All of these wells were drilled horizontally. The significant portion of acreage that is currently held by production should allow for efficient development utilizing pad drilling. Pad drilling minimizes the permit and infrastructure requirements and surface use.
 
Hydraulic Fracturing      We find that the use of hydraulic fracturing is necessary to produce commercial quantities of crude oil and natural gas from many reservoirs, including the DJ Basin, the Marcellus Shale, and the majority of our other onshore US operating areas. Hydraulic fracturing involves the injection of a mixture, comprised of water, sand and a small amount of chemicals, under pressure into rock formations to stimulate production of natural gas and/or oil from dense subsurface rock formations, including shale. The majority of our onshore US proved undeveloped reserves, which totaled 219 MMBoe at December 31, 2011, will require the use of hydraulic fracturing to produce commercial quantities of crude oil and natural gas. See Hydraulic Fracturing, below, for more discussion.
 
 
Other Onshore Properties   We operate in the following additional onshore US areas: Rocky Mountains including Piceance Basin (Western Colorado), Iron Horse in the Wind River Basin (Central Wyoming), Bowdoin field (North Central Montana), Tri-State field (Northeastern Colorado, Northwestern Kansas and Southwestern Nebraska), San Juan Basin (Northwestern New Mexico), and Powder River Basin (North/Central Wyoming); Mid-Continent including the Shattuck field (Western Oklahoma), Granite Wash field (Texas Panhandle), and East Mid-Continent (Central Kansas); and Gulf Coast including the Haynesville field (East Texas and North Louisiana) and other properties in Texas and Louisiana. Other onshore properties accounted for 17% of total consolidated sales volumes in 2011 and 8% of total proved reserves at December 31, 2011. Although our future development focus is concentrated on our five core areas, we continue to produce and develop in these other areas. We drilled 168 development wells during 2011 and plan to drill approximately ten development wells during 2012 in these areas.  Additionally, we continue to evaluate the divestment opportunities associated with certain non-core properties.  
 
Deepwater Gulf of Mexico    Locations of our deepwater Gulf of Mexico developments as of December 31, 2011 are shown on the map below:
 
IMAGE 2
 
The deepwater Gulf of Mexico is one of our core operating areas. Our focus is on high-impact opportunities with the potential to provide significant medium and long-term growth. We have four producing fields, multiple ongoing development projects and a substantial inventory of exploration opportunities.
 
The deepwater Gulf of Mexico accounted for 7% of total consolidated sales volumes in 2011 and 2% of total proved reserves at December 31, 2011. We currently hold leases on 102 deepwater Gulf of Mexico blocks, representing approximately 561,000 gross acres (403,000 net acres). Of our total gross acres, approximately 63,000 gross acres (33,000 net acres) have been developed. We are the operator on approximately 79% of the leases.
 
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. We currently have an inventory of 38 identified prospects, of which 23 are stand-alone, subsalt Miocene targets. The prospects are a combination of both large stand-alone prospects as well as a number of smaller, tie-back opportunities.  Prospects in inventory are subject to an ongoing rigorous technical maturation process and may or may not emerge as drillable options. To support the future appraisal work in our exploration inventory, we have contracted an additional drilling rig on a shared basis in 2012 and 2013. We will have two separate four-month slots with the ENSCO 8505, which will share the Gulf of Mexico workload with our currently contracted drilling rig, the ENSCO 8501. Utilizing these drilling rigs, during 2012, we plan to drill approximately four wells, up to two of which we currently anticipate to be at our Gunflint discovery.
 
In April 2010, the deepwater Gulf of Mexico drilling rig Deepwater Horizon, engaged in drilling operations for BP Exploration & Production Inc., sank after a blowout and fire (Deepwater Horizon Incident). The resulting leak caused a significant oil spill. In May 2010, due to the Deepwater Horizon Incident, 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). When the Deepwater Moratorium was announced, we were required to suspend drilling operations at Deep Blue and Santiago.  In April 2011, we announced that we had received the first post-moratorium blowout preventer certification, completion permit and drilling permit to resume drilling at our Santiago exploration well.  We also announced in December 2011 that we received a drilling permit to commence appraisal drilling at Gunflint.
 
 
Deep Blue    During 2011 we resumed drilling efforts at Deep Blue (Green Canyon Block 723; 33.75% operated working interest), which was initially spud in 2009 and suspended due to the Deepwater Moratorium. In November 2011, we announced that we had finished the well and found additional hydrocarbons in high quality reservoirs. During first quarter of 2012, we will be completing additional analysis of the data from the side track well.
 
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below.
 
Galapagos Development Project including Isabela (Mississippi Canyon Block 562; 33.33% non-operated working interest), Santa Cruz (Mississippi Canyon Blocks 519/563; 23.25% operated working interest) and Santiago (Mississippi Canyon Block 519; 23.25% operated working interest). The Galapagos crude oil development project consists of Isabela, a 2007 discovery, Santa Cruz, a 2009 discovery, and Santiago, a 2011 discovery. In 2009, we approved a phased development plan of the existing discoveries which includes completion of the wells and connection to the nearby Nakika production platform via subsea tieback. In May 2011, after receiving a permit to resume drilling, we announced that we had discovered commercial quantities of crude oil at Santiago, our third discovery at the Galapagos Development project. During the second quarter of 2011, we finished completion activities at Santiago. Installation of topside equipment at the host facility, and subsea tiebacks for Santa Cruz, Isabella, and Santiago are progressing. We currently expect production to commence in the second quarter of 2012.
 
Raton/South Raton (Mississippi Canyon Blocks 248 and 292)    Raton (67% operated working interest) was a 2006 natural gas discovery and has been producing since 2008. South Raton (79% operated working interest) was a 2008 crude oil discovery. Work to tie South Raton back to a non-operated host facility at Viosca Knoll Block 900 is ongoing with initial production scheduled for first quarter 2012.
 
Gunflint ( Mississippi Canyon Block 948; 26% operated working interest)    Gunflint is a 2008 crude oil discovery, our largest deepwater Gulf of Mexico discovery to date. During 2011, a unitization agreement covering the Gunflint discovery was finalized. The agreement named us as the operator and added the northern half of Mississippi Canyon blocks 992 and 993 to the project area which already included blocks 904, 948, and 949. Also as part of the agreement, our working interest was revised to 26%. Our plans to drill two or three appraisal wells during 2011 were delayed by impacts of the Deepwater Moratorium. In October 2011, we received a drilling permit and in December 2011 we resumed drilling at Gunflint.  Appraisal of Gunflint is necessary to narrow the resource range before final planning and sanctioning of a development project.  We currently anticipate drilling up to three appraisal wells to fully evaluate the extent of the reservoir.
 
We are reviewing host platform options including subsea tieback to an existing third-party host and construction of a new facility. We are currently targeting 2016 for production start-up. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule.
 
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest)    Swordfish was a 2001 discovery and began producing in 2005. The Swordfish project currently includes two producing wells connected to a third-party production facility through subsea 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 subsea tiebacks.
 
Lorien (Green Canyon Block 199; 60% operated working interest)    Lorien was a 2003 crude oil discovery and began producing in 2006.  The project currently includes one producing well connected to existing infrastructure through subea tiebacks.
 
International
 
Our international business focuses on offshore opportunities in multiple countries 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, Israel and Cyprus have identified multiple major development projects that are expected to 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 46% of total consolidated sales volumes in 2011 and 53% of total proved reserves at December 31, 2011. International proved reserves are approximately 80% natural gas and 20% crude oil and condensate. Operations in Equatorial Guinea, Cyprus, China and Senegal/Guinea-Bissau 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.
 
 
Locations of our international operations are shown on the map below:
 
IMAGE 3
 
Sales volumes and estimates of proved reserves for our international operating areas were as follows:
 
   
Year Ended December 31, 2011
   
December 31, 2011
 
   
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
    14       245       -       56       106       786       237  
Israel
    -       173       -       29       3       2,269       382  
North Sea
    8       5       -       9       9       11       10  
China
    4       -       -       4       7       1       7  
Total International
    26       423       -       98       125       3,067       636  
Equity Investee
    2       -       5       7       -       -       -  
Total
    28       423       5       105       125       3,067       636  
                                           
Equity Investee Share of Methanol Sales (MMgal)
              155                          

 
Wells drilled in 2011 and productive wells at December 31, 2011 in our international operating areas were as follows:

      Year Ended
December 31, 2011
      December 31, 2011  
     
Gross Wells Drilled
or Participated in
     
Gross Productive
Wells
 
International
               
Equatorial Guinea
   
2
     
18
 
Cameroon
   
1
     
-
 
Senegal/Guinea-Bissau
   
1
     
-
 
Israel
   
2
     
3
 
Cyprus
   
1
     
-
 
North Sea
   
-
     
27
 
China
   
5
     
25
 
Total International
   
12
     
73
 
 
West Africa (Equatorial Guinea, Cameroon and Senegal/Guinea-Bissau)   West Africa is one of our core operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo mining concession and Tilapia PSC offshore Cameroon, as well as the AGC Profond Block offshore Senegal/Guinea-Bissau. Equatorial Guinea accounted for approximately 26% of 2011 total consolidated sales volumes and 20% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 119,000 net developed acres and 137,000 net undeveloped acres in Equatorial Guinea, 563,000 net undeveloped acres in Cameroon, and 729,000 net undeveloped acres in Senegal/Guinea-Bissau.
 
Locations of our operations in West Africa are shown on the map below:
 
 
Alba Field    We have a 34% non-operated working interest in the Alba field, offshore Equatorial Guinea, which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, an LPG processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 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 under 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 under the equity method. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily 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 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 2012.
 
Aseng Project     Aseng is a crude oil development project on Block I (38% operated working interest) which includes five horizontal wells flowing to an FPSO (Aseng FPSO) where the production stream is separated.  The oil is stored on the Aseng FPSO until sold, while the natural gas and water are reinjected into the reservoir to maintain pressure and maximize oil recoveries. We are the technical operator of the Aseng Project.
 
The Aseng FPSO is designed to act as an oil production hub, as well as liquids storage and offloading hub, with capabilities to support future subsea oil field developments in the area. It also has the ability to take on board stabilized condensate from gas condensate fields in the area. It is capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjecting 160 MMcf/d of natural gas. Storage is approximately 1.6 MMBbls of liquids.
 
During 2011, we concluded construction of the Aseng FPSO, which arrived on location in Equatorial Guinea and completed field installation in late 2011.  We have executed an oil sale, purchase, and marketing agreement with Glencore Energy UK Ltd. for our share of Aseng production.
 
First production at Aseng commenced on November 6, 2011 and we completed three liftings totaling over 860 MBbl net in 2011.  As of December 31, 2011, we had net oil production of approximately 19 MBbl/d.
 
Alen Project    Alen, located primarily on Block O (45% operated 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 up to 440 MMcf/d of natural gas and 40 MBbl/d of condensate. We are the technical operator of the Alen Project.
 
During 2011, we began platform fabrication and commenced development drilling. First production at Alen is currently expected to commence by the fourth quarter of 2013 at 20 MBbl/d, net. Natural gas reinjection is estimated to be 390 MMcf/d during gas-recycling. The total gross development cost is estimated at $1.6 billion.  
 
Other Block O & I Projects     During the second quarter of 2011, we drilled the successful Diega appraisal well which encountered both crude oil and natural gas. We have drilled two sidetracks, each of which encountered hydrocarbons. We are currently finalizing our appraisal of Diega and are evaluating regional development scenarios.  Additionally, in late 2011, we drilled the Carla well, a successful oil appraisal well in Block O, offshore Equatorial Guinea. We are evaluating drilling results from our Diega and Carla discovery wells, and reviewing development options and formulating a development plan for these areas.
 
West Africa Gas Project      The Equatorial Guinea Ministry of Mines, Industry and Energy (MMIE) is considering the development of an integrated gas project (Integrated Project) which includes upstream gas projects, the required gas transportation system, and a second LNG train. Noble Energy, as Chair of the Integrated Project committee, is working with the MMIE and other Integrated Project stakeholders to determine the Integrated Project scope and schedule.
 
Cameroon    We have an interest in over one 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 2011, the 3-D seismic data acquired in 2003 and 2010 over the YoYo and Tilapia blocks was reprocessed for further interpretation. Additionally, during 2011 we drilled an exploration well testing the Bwabe prospect in the Tilapia Block, offshore Cameroon, reached total depth during late 2011 and did not find commercial quantities of hydrocarbons. We are currently evaluating several prospects as a follow-up for our offshore Cameroon exploration program.
 
Senegal/Guinea-Bissau     During 2011, we farmed into the AGC Profond block (30% non-operated working interest), which covers more than two million gross acres and includes a number of identified prospects. The joint venture drilled the Kora-1 exploration well during 2011.  The well did not result in commercial quantities of hydrocarbons; however, there are a number of prospects in the area.  We are working with our partners on future exploration plans and have the option to become the operator going forward.
 
 
Eastern Mediterranean (Israel and Cyprus )   Another core operating area is located in the Eastern Mediterranean. Israel accounted for 14% of 2011 total consolidated sales volumes and 31% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 80,000 net developed acres and 652,000 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 596,000 net undeveloped acres offshore Cyprus adjacent to our Israel acreage.
 
Locations of our operations in the Eastern Mediterranean are shown below:
 
IMAGE 5
 
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.  Natural gas sales began in 2004 and have increased steadily as Israel’s natural gas infrastructure has developed. Our share of sales volumes rose from 48 MMcf/d in 2004 to 173 MMcf/d in 2011. In total, we have delivered over 319 Bcf of natural gas, net, to Israeli customers through December 31, 2011.
 
During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes delivered at very high rates to support Israel’s growing gas and power demands. As a result, we experienced accelerated depletion of the Mari-B field. In January 2012, we announced a cut back in production at Mari-B to prudently manage the reservoir and preserve its deliverability for the peak demand months during the summer of 2012.

We are currently working closely with our Israeli customers to manage demand and operating the field so that it will produce until production commences at the Tamar field, which we expect to occur during the second quarter of 2013. At that time, we plan to transition the Mari-B reservoir to a natural gas storage facility. As a result of the accelerated depletion resulting from the high demand experienced as a result of Egyptian supply interruptions, we do not believe that the Mari-B field, alone, will be able to produce enough volumes to meet anticipated Israeli demand until production begins at Tamar. We are in the process of developing the Noa project and studying potential development of the Pinnacles project, both discussed below, to support near-term deliverability into the Israeli market. See also Delivery Commitments, below.
 
The Mari-B facility was designed to accommodate a certain amount of reservoir subsidence as the field depleted. As we near the end of the field’s producing life, the rate of subsidence could change, thereby increasing the risk of mechanical failure of individual wells and potentially decreasing the deliverability of the Mari-B field. See Item 1A. Risk Factors    Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues.
 
Noa Project    We are in the process of developing the Noa reserves (47% operated working interest) to support near-term deliverability to Israeli customers. The Noa project allows us to continue producing through the Mari-B platform at high rates, bringing another source of natural gas through our existing Mari-B facilities before Tamar begins producing. Two development wells have been drilled, engineering and design have been completed, and installation and fabrication are progressing on schedule.  First production at Noa is expected in the third quarter of 2012.
 
Pinnacles Project    We are also studying the potential development of Pinnacles, located near the Mari-B field, to help meet the Israeli natural gas demands. If partner approval is obtained and development occurs as expected, Pinnacles will begin producing in the third quarter of 2012.
 
 
Tamar Project    We discovered the Tamar natural gas field (36% operated working interest) offshore Israel in the Levant 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 commenced field development drilling, platform jacket and deck fabrication, pipeline installation and onshore facility expansion during 2011, with first production expected by second quarter of 2013. The total first phase development cost of Tamar is estimated at $3.0 billion ($1.1 billion net).
 
The Israeli natural gas market continues to grow, and the Tamar partners are in the final stages of sales contract negotiations with the Israel Electric Corporation Limited (IEC) and are in active discussions with existing and new customers to sell natural gas from the Tamar field. See International Marketing Activities and Delivery Commitments below.
 
We are considering the implementation of a floating LNG (FLNG) project at Tamar and have begun conducting preliminary engineering design work. The economic viability of such a large project is dependent on the ability to export natural gas to the international market. We are working with the Israeli government to obtain support for the project.
 
Leviathan Project    In December 2010, we announced a significant natural gas discovery at the Leviathan prospect (40% operated working interest) in the Levant Basin offshore Israel. The Leviathan field is the largest discovery in our history and was the world’s largest offshore natural gas discovery in 2010.
 
 
In early 2011, we drilled the Leviathan-2 appraisal well, which encountered wellbore issues resulting in our abandoning the well.  The incident was a covered event under our well control insurance; therefore, we expect to recover most of the costs from insurance, subject to a deductible.
 
We resumed the natural gas appraisal drilling program in mid-2011 with the successful Leviathan-3 appraisal well. In January 2012, we resumed 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 the first half of 2012.
 
We have project and commercial teams in place and are in the process of considering our commercialization options for Leviathan. Due to the size of the field, economic viability depends on the ability to export via pipeline or LNG. Engineering design and planning work are currently underway for a potential first phase of development; however, we have not yet sanctioned a development project.
 
Although we will be able to incorporate our knowledge gained on the Aseng and Tamar projects to Leviathan, such a complex, costly project is not without financial or execution risk. See item 1A. Risk Factors – The magnitude of our offshore Eastern Mediterranean discoveries will present financial and technical challenges for us due to the large-scale development requirements.
 
Dalit     Dalit (36% operated working interest) was our second 2009 natural gas discovery in the Levant Basin. We are currently working with our partners on a cost-effective development plan.
 
Dolphin 1     During the fourth quarter of 2011, w e completed drilling the successful Dolphin 1 (39.66% operated working interest) exploration well in the Hanna license, southwest of the Tamar gas field and are evaluating results.
 
Cyprus     During the fourth quarter of 2011, we drilled a successful natural gas exploration well (A-1) in Block 12. The well encountered approximately 310 feet of net natural gas pay in multiple high-quality Miocene sand intervals.
 
In 1974 the island of Cyprus was partitioned into two parts: the Republic of Cyprus with the majority of the south under its effective control, and the Turkish-controlled area in the north, which calls itself the Turkish Republic of Northern Cyprus. The United Nations recognizes the sovereignty of the Republic of Cyprus over the entire island. The Republic of Cyprus has been a member of the European Union since May 1, 2004.  The Turkish government opposes the current exploratory activities being conducted by the Republic of Cyprus, claiming such activities will have a detrimental effect on reunification negotiations, and that any development projects should be deferred until the dispute over the political status of the island is resolved.  While Turkey has voiced its opposition to the drilling operations, the European Union, Russia and the US have supported Cyprus' right to drill and our activities.
 
Other Exploration Activities
 
Tanin 1    During the fourth quarter of 2011, we spud the Tanin 1 (47.06% operated working interest) well in the Alon A block, offshore Israel.   In Febru ary 2012, we announced a natural gas discovery at Tanin.
 
Seismic
 
Israel    During 2011, we completed the 3-D seismic survey that was started in 2010 for the Ruth, Ratio, and Alon licenses, offshore Israel.
 
Cyprus    During 2011, we acquired approximately 1,544 square miles of 2-D seismic per our PSC work program.
 
See Item 1A. Risk Factors – Our international operations may be adversely affected by economic and political developments and Our operations may be adversely affected by civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts that may occur in regions that encompass our operations.
 
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 14 licenses on 15 blocks 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 have production 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 (GP III 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 2011, we began drilling a third Lochranza well and expect production to the Dumbarton facilities in early 2012.
 
We also participate in the Selkirk (30.5% non-operated working interest) project, located in the UK sector of the North Sea. We are currently working with our partners on development options.
 
 
The North Sea accounted for 4% of 2011 total consolidated sales volumes and 1% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 6,360 net developed acres and 29,130 net undeveloped acres. At December 31, 2011, we were running one horizontal rig and expect to drill one horizontal development well during 2012 at our Lochranza field.
 
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% non-operated working interest in the Cheng Dao Xi (CDX) field, which is located in the shallow water of the southern Bohai Bay. During 2011, we completed the commissioning of the newly installed B platform and commenced engineering and design of a third platform (C platform).  In addition, we drilled and completed six development wells, five of which were production wells and one water injection well. The drilling results in 2011 gave us additional confidence going forward on the western side of the block.
 
China accounted for 2% of 2011 total consolidated sales volumes and 1% of total proved reserves at December 31, 2011. At December 31, 2011, we held approximately 4,000 net developed acres and no undeveloped acres.
 
Other International Properties    At December 31, 2011, we held undeveloped acreage offshore in other international locations including Nicaragua, India and France. During 2011, we acquired 3-D seismic for Nicaragua.
 
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 Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves 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 (See Third-Party Reserves Audit below).
 
In addition, our Company-wide short-term incentive plan does 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 25 years of industry experience with positions of increasing responsibility in engineering and evaluations. The Vice President – Reserves reports directly to our Chief Executive Officer.
 
Technologies Used in Reserves Estimation    The SEC’s reserves 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 2011 reserves estimates.
 
Third-Party Reserves Audit     In each of the years 2011, 2010, and 2009, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2011 included a detailed review of 14 of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 80% of US proved reserves and 98% of international proved reserves (90% of total proved reserves). The reserves audit for 2010 included a detailed review of 13 of our major fields and covered approximately 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.
 
 
In connection with the 2011 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 production 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 have been prepared in accordance with the definitions and regulations 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, 2011, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. 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 2009 – 2011, our ten largest fields at the current time were audited. The Aseng field was first audited in 2009, the Tamar and Alen fields were first audited in 2010 and the Marcellus Shale field was first audited in 2011, 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. For proved reserves at December 31, 2011, on a quantity basis, the NSAI field estimates ranged from 17 MMBoe or 19% above to 14 MMBoe or 5% below as compared with our estimates on a field-by-field basis. 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, 2011 were, in the aggregate, approximately 18 MMBoe, or 2%.
 
Proved Undeveloped Reserves (PUDs)   As of December 31, 2011, our PUDs totaled 162 MMBbls of crude oil, condensate and NGLs and 3,257 Bcf of natural gas, for a total of 705 MMBoe.
 
PUDs Locations      We have several significant ongoing development projects which are in various stages of completion. PUDs are located as follows at December 31, 2011:
 
 
·
146 MMBoe in the DJ Basin, including Wattenberg, where we are projecting reasonable levels of increased activity with projected rig counts in line with past levels of operations;
 
·
21 MMBoe in the deepwater Gulf of Mexico, 91% of which are related to our Galapagos project, which is expected to be producing in the second quarter of 2012;
 
·
68 MMBoe in the Marcellus Shale;
 
·
94 MMBoe in Equatorial Guinea, 73% of which are in the Alba field with the remainder 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 Alen field PUDs are scheduled to be reclassified to proved developed reserves beginning in 2013;
 
·
365 MMBoe 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 second quarter 2013; and
 
·
the above fields represent 99% of total PUDs. The remaining 1% is associated with ongoing developments within the next five years in other onshore US and international areas.
 
Changes in PUDs     Changes in PUDs that occurred during the year were due to:

 
·
recording of approximately 56 MMBoe PUDs acquired in the Marcellus Shale Joint Venture transaction;
 
·
recording of approximately 58 MMBoe PUDs from ongoing onshore US development programs, primarily in Wattenberg and the Marcellus Shale;
 
 
 
·
recording of approximately 80 MMBoe PUDs from additional appraisal activity at Tamar, plus 3 MMBoe from other international areas;
 
·
conversion of approximately 45 MMBoe PUDs into proved developed reserves;
 
·
reclassification of approximately 28 MMBoe PUDs, primarily in Wattenberg including vertical Codell and J-Sand programs, that were not scheduled to be developed within five years due to additional shifting of activity to the horizontal Niobrara program;
 
·
negative revisions of approximately 10 MMBoe, primarily from dry-gas fields in the onshore US due to reduced activity assumptions; and
 
·
positive revisions of approximately 2 MMBoe in PUDs primarily due to changes in commodity prices.
 
Development Costs     Costs incurred   to advance the development of PUDs were approximately $1.4 billion in 2011 (including $66 million non-cash costs related to an increase in our Aseng FPSO lease obligation), $1.1 billion in 2010 (including $266 million non-cash costs related to an increase in our Aseng FPSO lease obligation), and $440 million in 2009 (including $29 million non-cash costs related to an increase in our Aseng FPSO lease obligation). A significant portion of costs incurred in 2011 related to our major development projects horizontal Niobrara, Aseng, Marcellus Shale, 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 $2.4 billion in 2012, $1.3 billion in 2013, and $1.0 billion in 2014. 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 PUDs drilling locations are scheduled to be drilled prior to the end of 2016.  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 2016.  Initial production from these PUDs is expected to begin during the years 2012 - 2016.
 
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; and
 
·
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, 2011, 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
   
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, 2011
                                           
United States
                                           
Wattenberg
    23       166       11     $ 90.05       $ 3.95     $ 49.45     $ 4.58  
Other US
    15       222       4       103.30         3.87       45.40       7.45  
Total US
    38       388       15       95.19         3.90       48.35       6.24  
Equatorial Guinea
                                                         
Alba Field (2)
    12       245       -       107.70         0.27       -       2.35  
Other
    2       -       -       106.87         -       -       9.08  
Mari-B Field (Israel)
    -       173       -       -         4.86       -       1.16  
North Sea
    8       5       -       112.97         8.11       -       14.95  
China
    4       -       -       106.19         -       -       9.61  
Total Consolidated Operations
    64       811       15       100.93         3.04       48.35       5.07  
Equity Investee (3)
    2       -       5       108.76         -       72.71          
Total
    66       811       20     $ 101.13       $ 3.04     $ 54.84          
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 (4)
    39       400       14       75.03         4.17       41.21       5.95  
Alba Field (Equatorial Guinea) (2)
    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 (5)
    -       25       -       -         -       -       -  
China
    4       -       -       75.15         -       -       7.49  
Total Consolidated Operations
    64       787       14       76.46         3.00       41.21       4.93  
Equity Investee (3)
    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 (4)
    37       397       10       55.19         3.61       27.96       6.26  
Alba Field (Equatorial Guinea) (2)
    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 (3)
    2       -       6       59.51         -       36.03          
Total
    64       781       16     $ 55.87       $ 2.54     $ 31.20          
 
(1)
Average production cost includes oil and gas operating costs and workover and repair expense and excludes production and ad valorem taxes and transportation expenses.
 
(2)
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.
 
Average crude oil sales prices reflect a reduction of $5.57 per Bbl (2009) from hedging activities. This price reduction resulted from hedge losses that were previously deferred in accumulated other comprehensive loss (AOCL). All hedge losses relating to Equatorial Guinea production had been reclassified to revenues by December 31, 2009.
 
(3)
Volumes represent sales of condensate and LPG from the LPG plant in Equatorial Guinea.
 
(4)
Average crude oil sales prices reflect reductions of $1.32 per Bbl (2010), and $2.13 per Bbl (2009) from hedging activities. Average natural gas sales prices reflect a decrease of $0.01 per Mcf (2010) from hedging activities. The effect of hedging activities on the average realized natural gas price for 2009 was de minimis. This price reduction resulted from losses that were previously deferred in AOCL. All hedge losses relating to US production had been reclassified to revenues by December 31, 2010.
 
(5)
Includes sales volumes 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 Exit from Ecuador above.
 
 
Revenues from sales of crude oil, natural gas and NGLs have accounted for 90% or more of consolidated revenues for each of the last three fiscal years.
 
At December 31, 2011, our operated properties accounted for approximately 67% 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, 2011 was as follows:
 
   
Crude Oil Wells
   
Natural Gas Wells
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
United States
    6,953       6,163.0       7,181       5,327.7       14,134       11,490.7  
Equatorial Guinea
    4       1.6       14       5.0       18       6.6  
Israel
    -       -       3       1.4       3       1.4  
North Sea
    18       4.0       9       1.0       27       5.0  
China
    24       13.7       1       0.6       25       14.3  
Total
    6,999       6,182.3       7,208       5,335.7       14,207       11,518.0  
 
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, 2011 was as follows:
 
   
Developed Acreage
   
Undeveloped Acreage
 
   
Gross
   
Net
   
Gross
   
Net
 
(thousands of acres)
                       
United States
                       
Onshore (1)
    2,065       1,305       1,890       1,351  
Offshore
    119       57       481       363  
Total United States
    2,184       1,362       2,371       1,714  
International
                               
Equatorial Guinea
    285       119       307       137  
Senegal/Guinea-Bissau
    -       -       2,431       729  
Cameroon
    -       -       1,125       563  
Israel
    185       80       1,469       652  
Cyprus (2)
    -       -       852       596  
North Sea (3)
    36       6       147       29  
China
    7       4       -       -  
France (4)
    -       -       2,808       2,036  
Nicaragua
    -       -       1,977       1,977  
India
    -       -       694       347  
Total International
    513       209       11,810       7,066  
Total
    2,697       1,571       14,181       8,780  
 
(1)
Includes approximately 464,000 gross (214,000 net) developed acres in the Marcellus Shale that are held by the production of others.
 
(2)
A portion of the acreage has been assigned to a partner and the agreement is awaiting government approval.
 
(3)
The North Sea includes acreage in the UK and the Netherlands.
 
(4)
We funded a 2-D seismic survey   over the acreage in return for a working interest in the concession.
 
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, licenses, or concessions, undeveloped acreage will expire over the next three years as follows:
 
   
Year Ended December 31,
 
   
2012
   
2013
   
2014
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
(thousands of acres)
                                   
Onshore US
    87       59       216       146       120       84  
Deepwater Gulf of Mexico
    40       21       37       17       29       20  
Equatorial Guinea
    -       -       307       137       -       -  
Israel (1)     198       93       1,209       537       -       -  
Cameroon (2)
    -       -       -       -       647       323  
Total
    325       173       1,769       837       796       427  
 
(1)
Represents acreage that will expire if no further action is taken to extend. We currently intend to extend the leases prior to expiration in accordance with license terms.
 
(2)
The acreage in Cameroon is comprised of our Tilapia PSC and our YoYo mining concession. Per our Tilapia PSC, we are required to drill two wells in the initial exploratory phase of our agreement which ends in July of 2012 to be eligible for an initial two year renewal period. Presently, we have drilled one well and we intend to drill the second well required under the agreement in the first half of 2012. At the end of the renewal period, ending in July 2014, there is a relinquishment requirement for 50% (479,000 gross acres) of the Tilapia acreage. Pursuant to the YoYo mining concession, if development is not commenced by December 2014, we will be required to relinquish all 168,000 acres we hold under the mining concession.
 
During 2011, the US Bureau of Safety and Environmental Enforcement (BSEE) granted one year extensions to the original terms of 26 of our deepwater Gulf of Mexico leases. To be eligible for an extension, each lease had to meet the following three criteria: no oil and gas production on the lease as of May 15, 2011, the lease includes water depths in excess of 500 feet, and the lease is scheduled to expire on or before December 31, 2015. The extensions were granted to allow more time to drill on offshore leases following the Deepwater Moratorium.
 
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, 2011
                                         
United States (1)
    9.6       3.7       13.3       641.2       4.0       645.2       658.5  
Equatorial Guinea (1)
    0.5       -       0.5       0.5       -       0.5       1.0  
Cameroon
    -       0.5       0.5       -       -       -       0.5  
Senegal/Guinea-Bissau
    -       0.3       0.3       -       -       -       0.3  
Israel (1)
    0.8       -       0.8       -       -       -       0.8  
Cyprus (1)
    0.7       -       0.7       -       -       -       0.7  
China
    -       -       -       2.9       -       2.9       2.9  
Total
    11.6       4.5       16.1       644.6       4.0       648.6       664.7  
Year Ended December 31, 2010
                                                       
United States (1)
    4.8       1.9       6.7       510.6       1.0       511.6       518.3  
Equatorial Guinea (1)
    -       -       -       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  
 
(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 2011 included in the table above, wells that were in the process of drilling or completing at December 31, 2011 were as follows:
 
   
Exploratory
   
Development
   
Total
 
   
Gross
   
Net
   
Gross
   
Net
   
Gross
   
Net
 
United States
    2       1.0       162       97.8       164       98.8  
Equatorial Guinea
    -       -       4       1.9       4       1.9  
Israel
    1       0.5       5       2.0       6       2.5  
Total
    3       1.5       171       101.7       174       103.2  
 
Oil Spill Response Preparedness   We maintain membership in Clean Gulf Associates (CGA), a nonprofit association of production and pipeline companies operating in the Gulf of Mexico. On behalf of its membership, CGA has contracted with Helix Energy Solutions Group (HESG) for the provision of subsea intervention, containment, capture and shut-in capacity for deepwater Gulf of Mexico exploration wells. The system, known as the Helix Fast Response System (HFRS), at full production capacity, can contain well leaks up to 55 MBbl/d of oil, 70 MBbl/d of liquids and 95 MMcf/d of natural gas, at 10,000 pounds per square inch (psi) in water depths to 10,000 feet. Resources also include a 15,000 psi-gauge intervention capping stack designed to shut-in wells, including extremely high-pressure, deeper wells in the deepwater Gulf of Mexico. We have entered into a separate utilization agreement with HESG which specifies the asset day rates should the HFRS system be deployed.
 
Internationally we maintain membership in Oil Spill Response Limited (OSRL). OSRL is an industry owned cooperative which exists to ensure effective response to oil spills wherever they occur. OSRL is an industry leader in oil spill preparedness and response services. We also maintain agreements internationally with Seacor. Seacor provides leased response equipment as well as oil spill response services. Additionally, in Equatorial Guinea, we are members of the Oil and Gas Operators Emergency Resource Allocation Group which shares equipment and resources in the event of a spill.
 
Domestic Marketing Activities    Crude oil, natural gas, condensate and NGLs produced in the US are generally sold under short-term and long-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    Our share of crude oil and condensate from the Aseng field is sold to Glencore Energy UK Ltd (Glencore Energy) under a long-term sales contract at market rates and is transported by tanker. 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 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. We have signed contracts and are engaged in active discussions for the sale of natural gas from the Tamar field with existing and new customers including multiple independent power producers, industrial, and cogeneration companies. In addition, we are in the final stages of sales contract negotiation with the IEC, currently our largest purchaser of gas in Israel, which is expected to purchase a significant portion of the Tamar production. See Delivery Commitments below.
 
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 through pipelines under a long-term contract at market-based prices.
 
Delivery Commitments      Some of our natural gas sales contracts specify the delivery of fixed and determinable quantities. As of December 31, 2011, remaining delivery commitments under existing natural gas sales contracts with Israeli customers totaled approximately 311 Bcf gross (146 Bcf, net). The majority of the quantities are expected to be delivered over a three year period with one commitment extending over a ten year period.
 
 
At December 31, 2011, we have recorded 83 Bcf, net, of proved developed natural gas reserves for Israel. Although this quantity of proved developed reserves itself would not be sufficient to meet delivery commitments scheduled within the next three years, we are in the process of developing reserves at Noa, which is scheduled to come online in the second half of 2012, and Tamar, which is scheduled to come online in the second quarter of 2013. We are also studying the potential development of Pinnacles, which, if developed as expected, would also come online in the second half of 2012. Based on the current timing of development plans for Noa and Tamar, and considering the potential development of Pinnacles, we will not be able to meet all contractual delivery commitments for portions of 2012 and 2013.  In January 2012, we issued force majeure notices to certain customers under the applicable contracts due to Mari-B depletion and its impact on the reservoir and facilities.
 
Our gas sales contracts have customary liability cap language that limits our financial exposure in the event we cannot fully deliver the contract quantities. Our liability will be reflected as a reduction in sales price for periods in which we are delivering partial contract quantities, or as a direct payment to the customer in the event that no production is available for delivery (subject to force majeure considerations). We believe that any such sales price adjustments or direct payments would not have a material impact on our earnings or cash flows.
 
Thus far in 2012, we have signed new natural gas sales contracts with Israeli customers to supply approximately 1,120 Bcf, gross (400 Bcf, net), of natural gas over a 16 to 17 year period beginning in late 2013. We expect to fulfill the delivery commitments with proved reserves from the Tamar field offshore Israel and do not expect any shortfall from these contracts. See International – Eastern Mediterranean (Israel and Cyprus) above.
 
 
Significant Purchaser    Glencore Energy was the largest single non-affiliated purchaser of 2011 production and purchased our share of crude oil and condensate production from the Alba and Aseng fields in Equatorial Guinea.  Sales to Glencore Energy accounted for 16% of 2011 total oil, gas and NGL sales, or 24% of 2011 crude oil sales. Shell Trading (US) Company (Shell) purchased crude oil and condensate from the North Sea and domestically from the deepwater Gulf of Mexico and the Wattenberg area. Sales to Shell accounted for 12% of 2011 total oil, gas and NGL sales, or 17% of crude oil sales. No other single non-affiliated purchaser accounted for 10% or more of oil and gas sales in 2011. 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 2011 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 the impact of 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.
 
Regulations
 
Government Regulation   Exploration for, and production and marketing of, crude oil and natural gas are extensively regulated at the international, federal, state, provincial 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 requirements on oil and gas 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 require extensive efforts to ensure compliance and incremental cost to comply, 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 requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors We are subject to increasing governmental regulations and environmental requirements that may cause us to incur substantial incremental costs.
 
Internationally, our operations are subject to legal and regulatory oversight by energy-related ministries or other agencies of our host countries, each having certain relevant energy or hydrocarbons laws. Examples include:
 
 
·
the Ministry of Mines, Industry and Energy which, under such laws as the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, regulates our exploration, development and production activities offshore Equatorial Guinea;
 
·
the Ministry of Energy and Water Resources which regulates both our exploration and development activities offshore Israel and the Israeli electricity market into which we sell our natural gas production;
 
·
the Ministry of Commerce, Industry, and Tourism which regulates our exploration and development activities offshore Cyprus;
 
·
the Department of Energy and Climate Change which regulates our exploration and development activities in the UK sector of the North Sea; and
 
·
various agencies in China which, under such laws as the Provisional Regulations on Administration and Management of the Abandonment of Offshore Oil and Gas Producing Facilities enacted in 2010, regulate our development and production activities offshore China.
 
Examples of other laws affecting our international operations are the Oil Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production in Israel, and the Finance Bill 2011, which increased the rate of the Supplementary Charge levied on oil and gas income in the UK.
 
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), the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE). The BOEM and the BSEE were formerly combined and operated as the Bureau of Ocean Energy Management, Regulation and Enforcement.  Under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, these bureaus 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 revenu e;
 
·
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (OSHA), 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 (FERC), 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 (DOT), which has certain authority over the transportation of products, equipment and personnel necessary to our onshore US and deepwater Gulf of Mexico operations.
 
Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In addition, we are governed by the rules and regulations of 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 rights, 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 that went into effect on January 1, 2010.The first annual report was due September 30, 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). Substantially all of our onshore US properties will be subject to the subpart W reporting requirements.
 
On July 28, 2011, the EPA issued proposed rules that would subject all oil and gas operations (production, processing, transmission, storage and distribution) to regulation under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants programs. The EPA proposed rules also include NSPS standards for completions of hydraulically fractured gas wells which would be applicable to newly drilled and fractured wells as well as existing wells that are refractured. Further, the proposed rules include maximum achievable control technology standards for certain equipment not currently subject to such standards.  Final action on the proposed rules is expected no later than February 28, 2012.
 
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 (Rule 318A), which was adopted by the Colorado Oil and Gas Conservation Commission (COGCC) to address oil and gas well drilling, production, commingling and spacing in Wattenberg. On August 9, 2011, the COGCC approved amendments to Rule 318A. The amendments, which became effective on October 1, 2011, remove the limit on the number of wells which can produce from a particular formation, allowing wellbore spacing units and permitting wells to cross section lines. The amendments also address areas such as infill drilling, water sampling and waste management plans. 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.
 
On October 3, 2011, Governor Tom Corbett of Pennsylvania announced his plan for state oversight of the Marcellus Shale natural gas industry. His plan includes numerous recommendations recently proposed by the Marcellus Shale Advisory Commission. Standards related to unconventional drilling would include increases in well setback distances, increases in bonding requirements, increases in penalties, expansion of the distance from a well for which a driller can be liable for environmental damage, and broadening of the Department of Environmental Protection’s authority to withhold or revoke permits. The plan also allows for an impact fee, which would be adopted by counties for use by local communities experiencing the actual impacts of drilling. The fee will be used by local governments, counties and state agencies that are involved in Marcellus Shale natural gas drilling. We are monitoring rule-making activities of the Pennsylvania legislature to assess the possible impact any recommendations could have on our business. Enactment of an impact fee and/or other proposals would likely result in a lower rate of return on our development project.
 
In December 2011, the West Virginia legislature passed, and the governor signed, the Natural Gas Horizontal Wells Control Act, which, among other things, provides for increased well permit fees, well location restrictions, well site safety, public notice requirements for municipalities, and regulations regarding water use and wastewater handling.
 
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.
 
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 requirements that may cause us to incur substantial incremental 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 necessary 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.
 
Hydraulic Fracturing
 
Concerns     The practice of hydraulic fracturing, especially the hydraulic fracturing processes associated with drilling in shale formations, has recently become the subject of significant focus among some environmentalists, regulators and the general public. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment have been raised at all levels, including federal, state and local, as well as internationally. There have been reports associating hydraulic fracturing with groundwater contamination, improper waste disposal, poor air quality and earthquakes.
 
Hydraulic fracturing requires the use and disposal of significant quantities of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply. Recently, there have been reports alleging contamination of drinking water supplies by chemicals linked to the hydraulic fracturing process. For example, in December 2011, the EPA issued a draft report which indicated that studies of a hydraulic fracturing site in Pavillion, Wyoming, not operated by Noble Energy, reportedly found hydraulic fracturing fluids and chemicals associated with natural gas production in deep water monitoring wells (Noble Energy has no interest in this field). The findings are not conclusive, and the EPA intends to submit its draft report to an independent scientific review panel.
 
Our Operations     Hydraulic fracturing techniques have been used by the industry for many years, and, currently, more than 90% of all oil and natural gas wells drilled in the US employ hydraulic fracturing. We strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into aquifers.  In the DJ Basin, we are in the process of securing additional water rights in support of our drilling program and implementing a pilot water recycling program. In the Marcellus Shale, our joint development agreement with CONSOL provides us with access to water resources which we believe will be adequate to execute our development program, and we anticipate the ability to recycle most of the water produced. We believe that these processes help ensure that hydraulic fracturing does not pose a meaningful risk to water supplies.
 
Potential Rulemaking      Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations.   For example, in 2011, the US Secretary of Energy formed the Shale Gas Production Subcommittee (Subcommittee), a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee was charged with making recommendations to improve the safety and environmental performance of hydraulic fracturing.  On August 18, 2011, the Subcommittee issued its Ninety Day Report (Report), which focused exclusively on the production of natural gas (and some liquid hydrocarbons) from shale formations with hydraulic fracturing stimulation in either vertical or horizontal wells. The Subcommittee identified four primary areas of concern including possible water pollution, air pollution, disruption of the community during production, and potential for adverse impact on communities and ecosystems. The Subcommittee also set forth a list of recommendations addressing, among other areas, communications, air quality, protection of water supply and quality, disclosure of fracturing fluid composition, reduction of diesel fuel use, continuous development of best practices, and federal sponsorship of research and development with respect to unconventional gas.  The Subcommittee issued its Final Report in November 2011 which recommends implementation of the Subcommittee’s recommendations by federal and state agencies.  We will continue to monitor the impact the Subcommittee’s recommendations, and any resulting rule-making activities evolving at federal and state levels, could have on our exploration and development activities in shale formations.
 
 
The EPA has commenced a study of the potential environmental impact of hydraulic fracturing, with initial results of the study anticipated to be available by late 2012. In addition, the EPA’s recently-issued proposed rules subjecting oil and gas operations to regulation under the New Source Performance Standards will be applicable to newly drilled and fractured wells as well as existing wells that are refractured.
 
We continue to monitor new and proposed legislation and regulations to assess the potential impact on our operations. We are currently evaluating the possible impact any proposed rules, such as those described above, could have on our business.  Any additional federal, state or local restrictions on hydraulic fracturing that may be imposed in areas in which we conduct business could result in substantial incremental operating, capital and compliance costs as well as delay our ability to develop oil and gas reserves.
 
Public Disclosure    Several states have issued regulations requiring disclosure of certain information regarding the components used in the hydraulic-fracturing process. In 2011, the Texas Railroad Commission (RRC) adopted the Hydraulic Fracturing Chemical Disclosure rule, under which companies are required to provide a listing of chemical ingredients used to hydraulically fracture wells that are permitted by the RRC on or after February 1, 2012 on a public national chemical disclosure registry, FracFocus.org, operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council. In December 2011, the COGCC adopted hydraulic fracturing fluid ingredient regulations requiring disclosure of all chemicals and establishing ways to protect proprietary information. The regulations allow disclosure through the FracFocus web site. The State of Wyoming also requires disclosure of the types and amounts of chemicals. Other states have proposed, or are considering, similar regulations which require specific disclosures by operators and/or outline requirements for construction and operation of wells and monitoring of well activity. We are currently providing voluntary disclosure information on FracFocus.org for the majority of our wells in Colorado and Wyoming and expect to expand our disclosures to comply with new state requirements and voluntarily disclose in all other areas in which we operate.
 
Additional Information     See:
 
 
·
Items 1. and 2. Business and Properties – Regulation;
 
·
Item 1A. Risk Factors – Federal or state hydraulic fracturing legislation could increase our costs or restrict our access to oil and gas reserves;
 
·
Item 1A. Risk Factors – Our ability to produce crude oil and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner ;
 
·
Item 1A. Risk Factors –   We face various risks associated with the trend toward increased anti-development activity ; and
 
·
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Risk and Insurance Program.
 
 
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, private equity, 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 6%, from 1,772 at December 31, 2010 to 1,876 at December 31, 2011, in support of our major development and exploration projects. The 2011 year-end employee count includes 135 foreign nationals working as employees in Ecuador, Israel, the UK, Equatorial Guinea, Cyprus, and Cameroon. We regularly use independent contractors and consultants to perform various field and other services.
 
Offices
 
Our principal corporate office is located at 100 Glenborough Drive, Suite 100, Houston, Texas 77067-3610. We maintain additional offices in Ardmore, Oklahoma; Denver, Colorado; and Canonsburg, Pennsylvania; and in China, Cameroon, Ecuador, Equatorial Guinea, Israel, Cyprus, Nicaragua, 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.
 
On September 7, 2011, an intermediate appellate court (Superior Court) of Pennsylvania issued an opinion in Butler v. Powers regarding the meaning of a deed. As a result, traditional views of how ownership of shale gas is determined in that state have been called into question. The issue is whether shale gas is different from other natural gas and should be considered part of mineral rights, rather than oil and gas rights, because it is contained inside rock. An appeal of the decision has been filed with the Pennsylvania Supreme Court. At this time, no case law or interpretation of existing law has changed, nor has there been an indication that either the Superior Court or the Pennsylvania Supreme Court will seek to change existing law. Based upon our initial review, we believe that any adverse decision in the pending case would have minimal adverse impact upon the assets acquired from CONSOL.
 
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. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.
 
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. On October 25, 2011 our Board approved and adopted a revised Code of Business Conduct and Ethics. Copies of the revised 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.
 
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 of operations 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 2011 ranged from a high of $113.93 per Bbl to a low of $75.76 per Bbl. The Brent daily average settlement price for the prompt month crude oil contract in 2011 ranged from a high of $126.65 per Bbl to a low of $93.33 per Bbl. The NYMEX monthly settlement price for the prompt month natural gas contract in 2011 ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu.
 
Thus far in 2012, there have been further declines in natural gas futures and spot prices. For example, the NYMEX January 2012 and February 2012 natural gas contracts settled at $3.08 per MMBtu and $2.68 per MMBtu, respectively. In addition, the quantity of natural gas currently being stored is at historically high levels relative to prior years.
 
The markets and prices for crude oil and natural gas depend on factors beyond our control, which factors include, among others:
 
 
·
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 (such as that produced from our Marcellus Shale properties) on the global natural gas supply;
 
·
the potential expansion of the global LNG market, including potential exports from the US;
 
·
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, solar, wind, 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.
 
Continuance of the current low natural gas price environment, further declines in natural gas prices, lack of natural gas storage, or a significant decline in crude oil prices may have the following effects on our business:
 
 
·
reduction of our revenues, operating income and cash flows;
 
·
curtailment or shut-in of our natural gas production due to lack of transportation or storage capacity;
 
·
reduction in the amount of crude oil and natural gas that we can produce economically;
 
·
cause certain properties in our portfolio to become economically unviable;
 
·
cause us to delay or postpone some of our capital projects, including our horizontal Niobrara and Marcellus Shale, deepwater Gulf of Mexico, or international development projects;
 
·
cause significant reductions in our capital investment programs, resulting in a failure to develop our reserves;
 
·
limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
 
·
limit our access to sources of capital, such as equity and long-term debt.
 
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 2009, 2010 and 2011;
 
·
additional counterparty credit risk exposure on commodity hedges; 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, liquidity and financial position.
 
We currently have an extensive inventory of major development projects, some of which will take several years before first production, such as Tamar, Alen, Gunflint, and Leviathan.  Some of these projects, such as oil and gas projects offshore West Africa and the Eastern Mediterranean, 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. In addition, we have expanded our horizontal drilling program in the Niobrara formation and entered into an agreement for the joint development of substantial acreage in the Marcellus Shale.
 
This level of development activity will require significant effort from our management and technical personnel as well as place additional requirements on our financial resources and internal financial controls. We may not have the ability to attract and/or retain the necessary number of personnel with the skills required to bring complicated projects to successful conclusions.
 
In addition, we have increased dependency on third-party technology and service providers and other supply chain participants 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 core areas may increase our risk of production loss.
 
Our operations are primarily concentrated in five core areas: the DJ Basin, the Marcellus Shale, and the deepwater Gulf of Mexico in the US, offshore West Africa, and the Eastern Mediterranean. These core 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, including non-core, non-strategic assets in the Gulf of Mexico shelf and onshore US, to high-grade and focus our portfolio. We are currently considering the divestiture of additional, non-core onshore US assets from our portfolio.
 
As a result of these portfolio changes, our operations and production are concentrated in fewer areas.  Although none of these areas represented more than 28% of our 2011 total 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 or limited access to reserves in one of our core operating areas could have a significant negative impact on our cash flows and profitability.
 
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 47% of our 2011 total sales volumes coming from international operations, and will be increasing our exposure through our major development projects offshore West Africa and the Eastern Mediterranean. 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 future proposals of Israel’s Interministerial Committee to Examine Government Policy on Israel’s Natural Gas Economy, 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;
 
·
changes in taxation policies, such as occurred pursuant to the Oil Profits Taxation Law, 2011, which imposed additional income tax on oil and gas production in Israel, and the Finance Bill 2011, which increased the rate of the Supplementary Charge levied on oil and gas income in the UK;
 
·
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 termination of our Block 3 PSC by the Ecuadorian government in 2010 pursuant to changes in Ecuador’s hydrocarbon law;
 
·
disruptions caused by territorial or boundary disputes in certain international regions, including the Eastern Mediterranean, where Lebanon has made claims related to our projects in Israeli waters and where in 2011 the Turkish government objected to exploratory activities conducted offshore the Republic of Cyprus, and in Central America where there is a dispute between Nicaragua and Colombia over the maritime border;
 
·
changes in drilling or safety regulations in other countries being considered as a result of the Deepwater Horizon Incident or other recent incidents that have occurred such as offshore Brazil and in China’s Bohai Bay, which could increase costs and development cycle time;
 
·
laws and policies of the US and foreign jurisdictions affecting foreign investment, taxation, trade and business conduct;
 
·
foreign exchange restrictions;