10-K 1 nbl-20121231x10kf.htm 10-K NBL-2012.12.31-10K FILE COPY
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2012
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
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, $0.01 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. ý 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 ý 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. ý 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). ý 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. ý 
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 ý No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2012: $15.1 billion.
Number of shares of Common Stock outstanding as of January 18, 2013: 178,714,869.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2012 Annual Meeting of Stockholders to be held on April 23, 2013, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2012, are incorporated by reference into Part III.





TABLE OF CONTENTS

PART I
Items 1. and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
 
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.





GLOSSARY
 
In this report, the following abbreviations are used:
 
Bbl
 
Barrel
BBoe
 
Billion barrels oil equivalent
Bcf
 
Billion cubic feet
Bcf/d
 
Billion cubic feet per day
BCM
 
Billion cubic meter
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
GHG
 
Greenhouse gas emissions
HH
 
Henry Hub index
LNG
 
Liquefied natural gas
LPG
 
Liquefied petroleum gas
MBbl/d
 
Thousand barrels per day
MBoe/d
 
Thousand barrels oil equivalent per day
Mcf
 
Thousand cubic feet
MMBbls
 
Million barrels
MMBoe
 
Million barrels oil equivalent
MMBtu
 
Million British thermal units
MMBtu/d
 
Million British thermal units per day
MMcf/d
 
Million cubic feet per day
MMcfe/d
 
Million cubic feet equivalent per day
MMgal
 
Million gallons
NGL
 
Natural gas liquids
NYMEX
 
The New York Mercantile Exchange
PSC
 
Production sharing contract
Tcf
 
Trillion cubic feet
US GAAP
 
United States generally accepted accounting principles
WTI
 
West Texas Intermediate index








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, the Company, we or us) is a leading independent energy company engaged in worldwide oil and gas exploration and production. Founded by Lloyd Noble in 1932, we recently celebrated the 80th anniversary of our founding. Noble Energy is a Delaware corporation, incorporated in 1969, and has been publicly traded on the New York Stock Exchange (NYSE) since 1980. We have a unique history of growth, evolving from a regional crude oil and natural gas producer to a global exploration and production company included in the S&P 500.
Our purpose, Energizing the World, Bettering People's Lives®, reflects our commitment to deliver energy through crude oil and natural gas exploration and production while embracing our responsibility to be a good corporate citizen and contribute to the betterment of people's lives in the communities in which we operate. We strive to build trust through stakeholder engagement, act on our values, provide a safe work environment, lead our industry, respect our environment and care for our people and the communities where we operate. In 2012, we published our first Sustainability Report.
We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified and growing 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, combined with the periodic divestment of non-core assets, have allowed us to achieve our objective of a diversified, growing asset portfolio offering superior returns to investors.
 
Our portfolio is diversified between short-term and long-term projects, both onshore and offshore, domestic and international. Our organization and business model is focused on sustainable, high return growth through the pursuit of material exploration opportunities which can be monetized on a competitive discovery-to-production cycle through highly capable major development project execution. Our first major offshore development project, Aseng, offshore Equatorial Guinea, began production in late 2011. We followed our success at Aseng with our second major development project, Galapagos, in the deepwater Gulf of Mexico, which began commercial crude oil production in June 2012. We remain on schedule with two major development projects, Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, scheduled to begin commercial production in the second and third quarters of 2013, respectively. Our ability to deliver these major development projects on schedule and budget provides a competitive and financial advantage in the industry.

Onshore US assets provide a stable base of production along with growing development programs and accommodate flexible capital spending programs that can be adjusted in response to ongoing changes in the economic environment. We continue to enhance project performance through technology and operational efficiency. Our long-term offshore development projects, while requiring multi-year capital investment, are expected to offer superior financial returns and cash flow coupled with 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.


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These five core areas provide:
 
the majority 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 liquidity levels. We strive to deliver competitive returns and a growing dividend. Our cash dividends have increased 38% in the last five years, from 66 cents per share in 2008 to 91 cents per share in 2012. See Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities - Stock Performance Graph and Item 6. Selected Financial Data for additional financial and operating information for fiscal years 2008-2012.

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.

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 progress, as appropriate, through the various development phases including appraisal and development drilling, front-end engineering and design, construction and exploitation. We currently have projects in all phases of the development cycle with some contributing production growth in 2012 and 2013, and others we are working to sanction with final investment decisions targeting first production from 2015 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)
·
Big Bend (deepwater Gulf of Mexico)
·
Tamar (offshore Israel)
·
Leviathan (offshore Israel)
·
Alen (offshore Equatorial Guinea)
·
Cyprus (offshore Cyprus)
 
 
·
Carla and Diega (offshore Equatorial Guinea)
 
 
·
West Africa gas project (offshore Equatorial Guinea)

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.


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Proved Oil and Gas Reserves    Proved reserves at December 31, 2012 were as follows:
 
Summary of 2012 Oil and Gas Reserves as of Fiscal-Year End
Based on Average 2012 Fiscal-Year Prices 
 
 
December 31, 2012
 
 
Proved Reserves
 
 
Crude Oil,
Condensate
& NGLs
 
Natural Gas
 
Total
Reserves Category
 
(MMBbls)
 
(Bcf)
 
(MMBoe)
Proved Developed
 
 
 
 
 
 
United States
 
130

 
1,042

 
303

Equatorial Guinea
 
60

 
514

 
146

Israel
 

 
18

 
3

Other International (1)
 
8

 
8

 
9

Total Proved Developed Reserves
 
198

 
1,582

 
461

Proved Undeveloped
 
 

 
 

 
 

United States
 
114

 
945

 
272

Equatorial Guinea
 
40

 
204

 
74

Israel
 
3

 
2,232

 
375

Other International (1)
 
2

 
1

 
2

Total Proved Undeveloped Reserves
 
159

 
3,382

 
723

Total Proved Reserves
 
357

 
4,964

 
1,184

 
(1) 
Other international includes the North Sea and China.

Total proved reserves as of December 31, 2012 were approximately 1.2 BBoe, a 2% decrease from 2011. US proved reserves accounted for 49% of the total, and international proved reserves accounted for 51%. Our 2012 proved reserves mix is 30% global liquids, 42% international natural gas, and 28% 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 our significant portfolio of major development projects. We have numerous exploration opportunities remaining in these areas and are also engaged in new venture activity in both the US and international locations. Our focus on exploration activities has created a sustainable industry-leading exploration program. During 2012, we expanded our global presence by entering into three new areas, onshore Northeast Nevada, offshore Falkland Islands and offshore Sierra Leone.
 
Appraisal, Development and Exploitation Activities   Our exploration success and strategic acquisitions have provided us with numerous appraisal, development, and exploitation opportunities, as demonstrated in our growing inventory of major development projects.  In 2012, we commenced crude oil production from Galapagos, deepwater Gulf of Mexico, our second major offshore development project, brought online following the start up of Aseng in 2011. Additionally, we continued to make significant progress on our other major development projects.
 

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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.
Strategic Partner for Leviathan   The Leviathan field, offshore Israel, is the largest conventional natural gas discovery in our history, with resources sufficient for both domestic demand and export. During 2012, we and our existing partners in the Leviathan project commenced a process to identify a partner who could provide technical and financial support as well as midstream and downstream expertise. On December 2, 2012, we and our existing partners announced that we had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. (Woodside). Woodside is Australia's largest producer of LNG with over 25 years of experience and has strong working relationships with many potential customers in the Asian LNG markets. We expect to execute a final agreement with Woodside during the first half of 2013. See Eastern Mediterranean (Israel and Cyprus) - Woodside Agreement, below.
Non-Core Divestiture Program Our non-core divestiture program is designed to generate organizational and operational efficiencies as well as cash for use in our capital investment program. Divestitures of non-core properties allow us to allocate capital and employee resources to high-growth, superior return areas. Proceeds from divestitures provide additional flexibility in the implementation of our international exploration and development programs and the acceleration of horizontal drilling activities in the DJ Basin and Marcellus Shale. During 2012, divestitures generated net proceeds of approximately $1.2 billion.

On August 13, 2012, we sold our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea, for $117 million, after final closing adjustments from the January 1, 2012 effective date. Net daily production from these properties was approximately 5 MBoe/d at the time of the sale.
 
During the third quarter of 2012, we closed on three sales of onshore US properties in Kansas, western Oklahoma, western Texas, and the Texas Panhandle for total proceeds of $1.0 billion. The properties included our interests in about 1,400 producing wells on approximately 109,000 net acres.  As of the effective date, April 1, 2012, net daily production on these properties was approximately 12.5 MBoe/d.

We sold approximately 57 MMBoe of proved reserves in 2012 and continue to market packages of non-core onshore US properties and our remaining North Sea properties.

Entry into Falkland Islands Joint Venture In August 2012, we entered into an agreement with Falkland Oil and Gas Limited (FOGL) and subsequently acquired an interest in FOGL's extensive license areas consisting of approximately 10 million undeveloped acres, gross, located south and east of the Falkland Islands.

Entry into Sierra Leone In September 2012, the Government of Sierra Leone awarded us participation in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million acres, gross. Under the terms of the award, Chevron (SL) Ltd. will be the operator and we will have a non-operated 30% working interest.

Exit from Senegal/Guinea-Bissau In 2012, we decided not to continue to participate in further appraisal activities and relinquished our acreage.

Exit from Ecuador In May 2011, we transferred our assets in Ecuador to the Ecuadorian government. We received cash proceeds of $73 million for the transfer of our offshore Amistad field assets, onshore gas processing facilities, 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.

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 diversifies 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 that is close to the US’s largest gas market, the Northeast US. It significantly increases our inventory of low risk, repeatable development 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 diversity to our rapidly expanding international programs.


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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.

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.

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.
  
Asset Impairments  During 2012, we recorded impairment charges of $104 million, related to our South Raton and Piceance developments due to near-term declines in crude oil and natural gas prices, respectively, and our Mari-B, Pinnacles and Noa fields, offshore Israel, due to end-of-field life declines in production. 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 60% of 2012 total consolidated sales volumes and 49% of total proved reserves at December 31, 2012. Approximately 58% of the proved reserves are natural gas and 42% 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, 2012
 
December 31, 2012
 
 
Sales Volumes
 
Proved Reserves
 
 
Crude Oil &
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
Crude Oil &
Condensate
 
Natural
Gas
 
NGLs
 
Total
 
 
(MBbl/d)
 
(MMcf/d)
 
(MBbl/d)
 
(MBoe/d)
 
(MMBbls)
 
(Bcf)
 
(MMBbls)
 
(MMBoe)
Wattenberg
 
32

 
194

 
13

 
77

 
150

 
880

 
61

 
358

Marcellus Shale
 

 
90

 

 
15

 

 
827

 
8

 
146

Rockies
 
2

 
117

 
2

 
24

 

 
203

 
3

 
37

Deepwater Gulf of Mexico
 
14

 
14

 
1

 
18

 
19

 
21

 

 
23

Gulf Coast and Other
 
1

 
23

 

 
5

 
3

 
56

 

 
11

Total
 
49

 
438

 
16

 
139

 
172

 
1,987

 
72

 
575

 
Wells drilled in 2012 and productive wells at December 31, 2012 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2012
 
December 31, 2012
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
Wattenberg
 
555

 
8,954

Marcellus Shale
 
71

 
173

Rockies
 
24

 
4,210

Deepwater Gulf of Mexico
 
1

 
11

Gulf Coast and Other
 

 
313

Total
 
651

 
13,661


(1) 
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well. See Drilling Activity below.


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 Locations of our onshore US operations as of December 31, 2012 are shown on the map below:

DJ Basin / Wattenberg The DJ Basin, where we have an acreage position of approximately 750,000 net acres, is a premier US crude oil resource play and is significant to our production growth and development activities. Included in the DJ Basin is Wattenberg (approximately 95% operated working interest), our largest onshore US asset, where we have a multi-year project inventory. In 2012, we continued to improve our operational performance while accelerating our drilling activities. During 2012, we had record sales volumes in the DJ Basin due to continued strong performance from our horizontal drilling program that began in 2010.
Wattenberg includes:
 
the Greater Wattenberg Area (GWA), where we have conducted substantial vertical development over the last several years as well as successful horizontal drilling in the high density area and more recently in the less developed northeastern part of GWA. The area is comprised of both an expanding crude oil window to the northeast and strong natural gas window in the core and to the southwest; and
northern Colorado from the edge of the GWA to the Wyoming border where we expanded our acreage position and drilled over 25 wells during 2012.

During 2012, we spud a total of 410 development wells in Wattenberg, of which 195 were horizontal wells into the Niobrara and Codell formations. In 2011, we began constructing multi-well horizontal drilling pads and centralized production facilities to minimize our surface use (EcoNode). The EcoNode allows for more efficient execution and operations by reducing our land use and surface traffic, water usage and moving the program forward with less surface impact.  We continue to evaluate impacts of changes in well spacing and pad design. Included in the well numbers above, we spud 10 extended-reach (7,000 - 9,000 feet) lateral wells as part of the 2012 drilling program and are planning for approximately 20% of our 2013 drilling program to be extended-reach wells.
Wattenberg contributed an average of 77 MBoe/d of sales volumes, represented approximately 33% of total consolidated sales volumes in 2012, with approximately 58% being liquids, and approximately 358 MMBoe or 31% of total proved reserves at December 31, 2012. Horizontal drilling in the Niobrara formation has significantly expanded the economic limits of this field. Of the net sales volumes from Wattenberg, approximately 28 MBoe/d, came from a total of 279 producing wells in our horizontal Niobrara program.

During 2012, we continued to expand our horizontal Niobrara development activities into Northern Colorado, where recent results indicate recoveries comparable to those in the GWA. We added almost 26,000 net acres to our Northern Colorado position this year, increasing our acreage position to approximately 230,000 net acres. We expect to spud approximately 80 to 90 wells in this area during 2013, further accelerating our horizontal Niobrara development.

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Our 2012 Wattenberg development program resulted in additions to proved reserves of approximately 55 MMBoe, approximately 72% of which are liquids.
Our DJ Basin position gives us opportunities to expand beyond our GWA development activities. We have also expanded into Wyoming and continue to appraise this acreage.
Marcellus Shale   A joint venture partnership with CONSOL Energy Inc. (CONSOL), formed in September 2011, the Marcellus Shale represents our second onshore US core area. We hold a 50% interest in approximately 628,000 net acres in southwest Pennsylvania and northwest West Virginia. We operate the wet gas development area while CONSOL operates the dry gas development area.
During 2012, we drilled to total depths approximately 25 wet gas wells and began wet gas production in July 2012. By applying our DJ Basin experience, we continue to test the limits of our recovery techniques with longer lateral wells, improved hydraulic fracturing design and optimal well placements. As we move into new areas, water supply and gas gathering infrastructure are expanding. Our partner, CONSOL, drilled to total depths 64 dry gas wells during 2012. Although we have reduced drilling in the dry gas area due to the low natural gas price environment, the dry gas portion of the program continues to deliver economically attractive returns due to strong production performance, high net revenue interests, competitive costs, partner alignment, and access to the US's largest gas market in the Northeast.
The Marcellus Shale contributed an average of 15 MBoe/d of sales volumes and represented approximately 6% of total consolidated sales volumes in 2012, with approximately 1% being liquids, and approximately 146 MMBoe or 12% of total proved reserves at December 31, 2012.
Our joint development plan for 2013 projects that we will drill to total depth approximately 90 horizontal wells in the wet gas areas and CONSOL will drill to total depth approximately 36 horizontal wells focused in the dry gas areas of the Marcellus Shale.
The large portion of acreage that is currently held by production should allow for efficient development utilizing pad drilling. Pad drilling minimizes our surface use as well as the permitting and infrastructure requirements. 
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 and the Marcellus Shale. Hydraulic fracturing involves the injection of a mixture of pressurized water, sand and a small amount of chemicals into rock formations in order 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 265 MMBoe at December 31, 2012, will require the use of hydraulic fracturing to produce commercial quantities of crude oil and natural gas. See Hydraulic Fracturing, below, for more discussion.
Natural Gas Flaring The practice of natural gas flaring (burning) is the safest way to dispose of natural gas associated with crude oil production when no gas infrastructure is available. The volume of natural gas being flared is growing in certain areas of the US, such as the Bakken Shale, primarily as a result of increased oil shale drilling activity and limited natural gas infrastructure. In these areas, public concern has grown about the potential impact of GHG emissions from flaring on the environment, as well as the potential waste of natural resources.
In our DJ Basin and Marcellus Shale operations, natural gas infrastructure build out generally occurs in advance of drilling activity. If short-term flaring is necessary, we use efficient, environmentally protective and energy-saving flaring technologies. We participate in the Carbon Disclosure Project by publicly disclosing, on a voluntary basis, information pertaining to our GHG emissions.
Northeast Nevada   We constantly strive to identify new onshore exploration opportunities with reasonable entry cost, significant running room and the potential to become a new core area. We have a 350,000 net acre position (66% fee acreage and remainder federal acreage) in Northeast Nevada, prospective for oil exploration, which we identified through basin scale reconnaissance and innovative geoscience concepts. We acquired 3-D seismic over portions of the acreage in 2012 with a vertical well exploratory drilling program scheduled to begin in 2013.
Other Onshore Properties   We also operate in the following onshore US areas: Rocky Mountains including Piceance Basin (Western Colorado), 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); and Gulf Coast including the Haynesville field (East Texas and North Louisiana) and other properties in Texas and Louisiana. Other onshore properties accounted for 13% of total consolidated sales volumes in 2012 and 4% of total proved reserves at December 31, 2012. Although our future development focus is concentrated on our core areas, we continue to produce and develop in these other areas. We drilled 22 development wells during 2012.  During 2012, we completed the sale of various

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non-core onshore properties and continue to evaluate the divestment opportunities associated with other non-core properties. See Acquisition and Divestiture Activities - Non-Core Divestiture Program above.
Deepwater Gulf of Mexico   Locations of our deepwater Gulf of Mexico developments as of December 31, 2012 are shown on the map below:
 
Noble Energy was one of the first independent producers to explore in the Gulf of Mexico. We acquired our first offshore block in 1968, and today 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 six producing fields, multiple ongoing development projects and a substantial inventory of exploration opportunities.
 
The deepwater Gulf of Mexico accounted for 8% of total consolidated sales volumes in 2012 and 2% of total proved reserves at December 31, 2012. We currently hold leases on 102 deepwater Gulf of Mexico blocks, representing approximately 596,000 gross acres (414,000 net acres). Of our total gross acres, approximately 96,000 gross acres (41,000 net acres) have been developed. We are the operator on approximately 86% of our leases. See also Developed and Undeveloped Acreage - Future Acreage Expirations, below.
 
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 31 identified prospects, which are a combination of both high impact stand-alone subsalt prospects and smaller, high value tie-back opportunities.  The prospects are subject to an ongoing rigorous technical maturation process and may or may not emerge as drillable options. To support the future exploration, appraisal, and development work, we have the ENSCO 8501 rig under contract through most of 2013 with four additional one year option elections. We also have the ENSCO 8505 rig under contract through 2014 in a rig share agreement with two other operators; however, we farmed out our 2013 drilling slot to our rig partners. In 2013, we plan to drill a Gunflint appraisal well and at least one exploration well.
Big Bend   During 2012, we drilled the successful Big Bend exploration well. The well is located in Mississippi Canyon Block 698 and was drilled to a total depth of 15,989 feet. We hold a 54% operated working interest in Big Bend. Logging results identified approximately 150 feet of net oil pay in two high-quality reservoirs. We anticipate sanctioning a development plan for Big Bend during 2013 with first production targeted in late 2015 or early 2016.
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. During 2012, we completed the subsea tieback to the nearby Nakika production platform and began production in June. The Galapagos development has significantly increased our offshore production in 2012 with flow rates up to approximately 13.5 MBoe/d, net.

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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. In July 2012, we drilled a successful Gunflint appraisal well. During first quarter of 2013, we plan to drill our second appraisal well targeting the southern area of the reservoir. Front-end conceptual studies have been completed, and we are working toward sanctioning of a scalable development project in 2013. We are currently targeting 2017 for production start-up utilizing a standalone facility. If we choose to connect to an existing third-party host, the project could have an accelerated completion schedule.
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. During the second quarter of 2012, the South Raton crude oil development project commenced production at approximately 3 MBbl/d, net. South Raton is tied back to a non-operated host facility. We are currently evaluating mechanical issues at South Raton, which is temporarily offline.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest)   Swordfish was a 2001 crude oil 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 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 in 2012 we entered two new areas: offshore the Falkland Islands and offshore Sierra Leone. Each of these locations will provide further international exploration opportunities.
 
In furtherance of our commitment to global offshore exploration and development, on September 27, 2012, we announced that we have entered into a 36-month drilling services contract with a subsidiary of Atwood Oceanics, Inc. Drilling services will be provided by a new-build drillship, the Atwood Advantage. The Atwood Advantage is currently under construction by Daewoo Shipbuilding & Marine Engineering Co., Ltd. in South Korea. The drillship will be equipped with enhanced offline capabilities, such as dual blowout preventer stacks that allow for simultaneous inspection and drilling activities, and will be rated for operations in 12,000 feet water depth/40,000 feet drill depth. The increased mobility of the Atwood Advantage, as compared with other drilling rigs, will add flexibility to our global exploration program. We expect that the drillship will be available fourth quarter 2013 and initially deployed offshore Israel.
International operations accounted for 40% of total consolidated sales volumes in 2012 and 51% of total proved reserves at December 31, 2012. International proved reserves are approximately 81% natural gas and 19% crude oil and condensate. Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone 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 Nicaragua, the Falkland Islands, the North Sea, Israel, and other foreign locations are conducted in accordance with concession agreements, permits or licenses.

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


Sales volumes and estimates of proved reserves for our international operating areas were as follows: 
 
 
Year Ended December 31, 2012
 
December 31, 2012
 
 
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
 
33

 
235

 

 
72

 
100

 
718

 
220

Israel
 

 
101

 

 
17

 
3

 
2,250

 
378

China
 
4

 

 

 
4

 
7

 
2

 
7

Total International
 
37

 
336

 

 
93

 
110

 
2,970

 
605

Equity Investee
 
2

 

 
5

 
7

 

 

 

Discontinued Operations (North Sea)
 
5

 
4

 

 
5

 
3

 
7

 
4

Total
 
44

 
340

 
5

 
105

 
113

 
2,977

 
609

Equity Investee Share of Methanol Sales (MMgal)
 
 

 
156

 
 

 
 

 
 



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Wells drilled in 2012 and productive wells at December 31, 2012 in our international operating areas were as follows:
 
 
Year Ended December 31, 2012
 
December 31, 2012
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
International
 
 
 
 
Equatorial Guinea
 
4

 
23

Cameroon
 
1

 

Israel
 
8

 
9

North Sea
 

 
18

China
 
3

 
28

Total International
 
16

 
78


(1) 
Excludes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well. See Drilling Activity below.

West Africa (Equatorial Guinea, Cameroon and Sierra Leone)   West Africa is one of our core operating areas and includes the Alba field, Block O and Block I offshore Equatorial Guinea, as well as the YoYo mining concession and Tilapia PSC offshore Cameroon and two new blocks offshore Sierra Leone. Equatorial Guinea, the only producing country in our West Africa segment, accounted for approximately 31% of 2012 total consolidated sales volumes and 18% of total proved reserves at December 31, 2012. At December 31, 2012, we held approximately 119,000 net developed acres and 80,000 net undeveloped acres in Equatorial Guinea, 542,000 net undeveloped acres in Cameroon, and 414,000 net undeveloped acres in Sierra Leone.

Locations of our operations in West Africa are shown on the map below:

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 and have executed a crude oil sale, purchase, and marketing agreement with Glencore Energy UK Ltd. for our share of Aseng production.
 

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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 process and store stabilized condensate from gas condensate fields in the area, the first of which will be Alen during the third quarter of 2013. It is capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjecting 160 MMcf/d of natural gas. The Aseng FPSO has storage capacity of approximately 1.6 MMBbls of liquids. 
During 2012, Aseng maintained excellent reliability and safety performance and averaged almost 100% production uptime, while producing on average 62 MBbl/d, 21 MBbl/d net, to Noble Energy.
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, Equatorial Guinea. 
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 as an equity method investment. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest, also accounted for as an equity method investment. 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.
In December 2012, the Alba compression project was approved. We are beginning the engineering phase for a compression platform and related in-field connections in early 2013 with an estimated start-up in 2016. 
Alen Project   Alen, sanctioned in 2010, is located primarily on Block O (45% operated working interest), offshore Equatorial Guinea, and is our next West Africa major 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 utilizing the hub we are in the process of building in the region, where it will be held until sold. The 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.
Alen is progressing ahead of schedule and below budget. The total gross development cost is trending below sanction cost of $1.4 billion with first production currently expected during the third quarter of 2013 at 18 MBbl/d, net. The sanctioned plan originally scheduled commencement late fourth quarter of 2013. Significant effort has been placed to remove the risk from the schedule by completing as much of the field work as possible early in development. The wells are drilled and completed, the well-protector and jacket are installed, and the flowlines are in place. The final infrastructure, the topsides for the well-protector platform and the central platform, are expected to arrive in West Africa late March 2013 to begin installation. 
Other Block O & I Projects    We are continuing our exploration and appraisal efforts offshore Equatorial Guinea, where we still have numerous opportunities. We continue the appraisal program for our Carla and Diega discoveries, where we have encountered hydrocarbons in multiple appraisal wells and side-tracks.
During 2012, we identified a crude oil reservoir below the Alen field while drilling additional Carla appraisal wells. Development plans are being prepared for possible sanctioning of Carla during 2013, which would have a target first production at 11 MBbl/d, net, in early 2016. Carla further demonstrates the value of the infrastructure we are building that allows us to have host facilities and tie back additional fields.
We are continuing to review drilling results from our Diega discovery wells, finalizing an appraisal design program, and continue to evaluate regional development scenarios for the asset. We plan to begin appraisal drilling in the second half of 2013 or early 2014.
West Africa Gas Project    We have a natural gas development team working with the Equatorial Guinea Ministry of Mines, Industry and Energy in evaluating several monetization options for natural gas that would be produced from Blocks O and I.
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 2012, we drilled the Trema exploration well testing the Tilapia Block, offshore Cameroon, but did not locate commercial quantities of hydrocarbons. We are currently evaluating prospects as a follow-up for our offshore Cameroon exploration program.
 

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Sierra Leone During 2012, the Government of Sierra Leone awarded us participation in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million gross acres. Under the terms of the award, Chevron (SL) Ltd. will be the operator and we will have a non-operated 30% working interest. We plan to begin acquiring 2-D seismic information over portions of the acreage in 2013 to assist with our 3-D seismic plans. See Item 1A. Risk Factors - Our entry into new exploration ventures in areas in which we have no prior experience subjects us to additional risks.
Senegal/Guinea-Bissau During 2011, we farmed into the AGC Profond block (30% non-operated working interest) and the joint venture drilled the Kora-1 exploration well. The well did not result in commercial quantities of hydrocarbons. During 2012, we decided not to participate in the second appraisal period and relinquished our acreage. The cost associated with the undeveloped leasehold was charged to exploration expense in third quarter 2012.

Eastern Mediterranean (Israel and Cyprus)   Another core operating area is located in the Eastern Mediterranean, where we have had six consecutive natural gas discoveries in recent years. We are also beginning to explore for potential thermogenic (crude oil generating) hydrocarbon systems which may exist at greater depths.

Israel, the only producing country in our Eastern Mediterranean segment, accounted for 7% of 2012 total consolidated sales volumes and 32% of total proved reserves at December 31, 2012. At December 31, 2012, we held approximately 58,000 net developed acres and 581,000 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 13 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:

 

Domestic Natural Gas Demand As the Israeli economy continues to grow, so does the demand for natural gas, which is currently used primarily for electricity generation. Demand for natural gas in the industrial sector, including refineries, chemical, desalination, cement and other plants, is also increasing. These sectors are gaining confidence that a long-term supply

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of natural gas will be available and are therefore willing to make the capital investment necessary to convert facilities to use natural gas. We expect that government requirements for emissions reductions could also drive demand for natural gas as fuel.
Natural Gas Export As discussed below, we have made significant natural gas discoveries in the Eastern Mediterranean. Although we continue to conduct appraisal activities, we expect that the quantity of natural gas discovered can be used to satisfy growing domestic demand as well as provide sufficient resources for export. Eastern Mediterranean export projects would be well positioned to supply growing global natural gas demand, and, as discussed further below, we are considering multiple options. The government of Israel is in the process of finalizing an export policy. See Regulations - Israeli Interministerial Committee, below.
Tamar Natural Gas 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 and is currently one of our major development projects.  We expect first delivery of gas to customers in April 2013, four years from discovery and two and a half years from project sanction. 
Tamar Phase 1 development includes five subsea wells with a combined production capacity of 985 MMcf/d, with identified expansion capability to approximately 1.5 Bcf/d. The natural gas produced at these wells will flow to a new offshore platform constructed near the existing Mari-B platform. The natural gas will then be delivered to the existing pipeline that connects the Mari-B field to the Ashdod onshore terminal. Tamar's 93-mile tieback, originating in a water depth in excess of 5,000 feet, is the longest subsea tieback in the world.
The Tamar partners have executed numerous gas sale and purchase agreements (Tamar GSPAs) for the initial and expanded capacity as well as a condensate sales agreement. See International Marketing Activities and Delivery Commitments below. In addition, a floating LNG (FLNG) project is under evaluation.
Leviathan Natural Gas Project   In December 2010, we announced a significant natural gas discovery at the Leviathan-1 well (39.66% operated working interest) offshore Israel in the Levant Basin. The Leviathan field is the largest discovery in our history and was the world's largest offshore natural gas discovery in 2010. The Leviathan-2 well was plugged due to wellbore issues. In 2012, we drilled the successful Leviathan-3 appraisal well and spud the Leviathan-4 appraisal well.
We have project and commercial teams in place and are in the process of screening multiple development concepts. Due to Leviathan's size, full field development and realization of maximum economic value is expected to require several development phases.
The Leviathan Phase 1 development concept includes offshore processing at an FPSO, with a production capacity of 1.6 Bcf/d and a capability to serve both domestic demand and export. Domestic production could begin as early as 2016. This option will enable us to begin production within three years of license to lease conversion. Phase 2, an additional FPSO, is expected to have a similar production capacity and capability.
Multiple export options, including onshore LNG, FLNG and pipeline are under evaluation. Timing of project sanction depends on execution of natural gas sales contracts, determination of an onshore entry point and government approvals.
Woodside Agreement On December 2, 2012, we and our existing partners in the Leviathan project announced that we had agreed in principle on a proposal to sell a 30% working interest in the Leviathan licenses to Woodside Energy Ltd. Each of the current Leviathan partners is expected to participate as a seller to Woodside. We expect to convey a 9.66% working interest, reducing our working interest to 30%, and continue as upstream operator. The transaction is subject to the negotiations and execution of definitive agreements between the parties, as well as customary approvals, prior to closing.
According to the initial proposal, we would receive net cash payments totaling $464 million, a portion of which would be paid only upon the occurrence of certain future events. The payments, subject to definitive agreement, include the following:
$287 million initial cash payment payable at closing;
$64 million contingent on the ability to export natural gas; and
$113 million contingent on a final investment decision for an LNG project.

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Additional payments, subject to definitive agreement, would include the following:
a share of Woodside's annual LNG revenue above certain price parameters, subject to a $322 million cap over the life of the project; and
a drilling carry of up to $16 million on the drilling of the planned Mesozoic oil exploration well.
Including the potential revenue sharing amounts and drilling carry, the implied price for our 9.66% working interest being sold totals $802 million under the initial proposal. Negotiations continue, and, as a result, this amount could change. We expect to execute a final agreement with Woodside during the first half of 2013. In conjunction with these negotiations, we are assisting our current Leviathan partners to obtain appropriate financing for their share of development costs and considering providing a limited amount of financial backstop to them.
Leviathan-1 Deep (Mesozoic Oil Target) In January 2012, we returned to the Leviathan-1 well and began drilling toward two deeper intervals in order to evaluate them for the existence of crude oil (Leviathan-1 Deep). In May 2012, due to high well pressure and the mechanical limits of the wellbore design, we suspended drilling operations. Although the well did not reach the planned objective, we are encouraged by the possibility of an active thermogenic (crude oil generating) hydrocarbon system at greater depths within the basin.
We will integrate the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically to test the deep oil concept. We have entered into a contract for drilling services to be provided by the Atwood Advantage drillship, which will be rated for operations in 12,000 feet water depth/40,000 feet drill depth with the capabilities necessary to reach the target objective, and plan to begin drilling an exploratory well in the fourth quarter of 2013.
Mari-B, Pinnacles and Noa Fields The Mari-B field (47% operated working interest) was the first offshore natural gas production facility in Israel and has been producing since 2004. Through December 31, 2012, we have delivered over 420 Bcf of natural gas, net, to Israeli customers.
During 2011, due to multiple interruptions in imported gas supplies from Egypt, Mari-B natural gas volumes were delivered at very high rates to support Israel's growing natural gas and power demands. As a result, the Mari-B field experienced accelerated depletion. In January 2012, we announced a cut back in production at Mari-B to prudently manage the reservoir. We have been working closely with our Israeli customers to manage demand on the Mari-B field and continue production from it.
In order to help meet Israeli natural gas demand until the Tamar field begins producing, we completed the Noa (47% operated working interest) and Pinnacles (47% operated working interest) wells and tied them back to the Mari-B platform. We began selling natural gas from Noa in June 2012 and Pinnacles in July 2012. At December 31, 2012, we recorded an impairment charge of $31 million for the combined Mari-B, Noa, and Pinnacles wells due to end-of-field life declines in production. See Item 8. Financial Statements and Supplementary Financial Data - Note 4. Asset Impairments.
We expect to continue producing from Mari-B, Noa and Pinnacles until production commences at the Tamar field. Once Tamar begins producing, Mari-B, Noa and Pinnacles production volumes will be reduced, and we plan to transition the Mari-B reservoir to a natural gas storage facility. We will continue to provide natural gas to Israeli purchasers under several natural gas sales and purchase agreements for which the total contract quantities have not been met. See Delivery Commitments and Item 1A. Risk Factors - Exploration, development and production risks and natural disasters could result in liability exposure or the loss of production and revenues
Other Discoveries Offshore Israel   We and our partners are working on a development plan for the Dalit field (36% operated working interest), a 2009 natural gas discovery. Development would include tie-in to the Tamar platform, and we have submitted a development plan to the Israeli government. In addition, we are reviewing alternatives for the development of the Dolphin (39.66% operated working interest) and Tanin 1 (47.06% operated working interest) natural gas discoveries.
Cyprus    During the fourth quarter of 2011, we made another natural gas discovery when we drilled the successful A-1 exploration well in Block 12, offshore Cyprus. We are planning to drill an appraisal well in 2013 and are working with the government of Cyprus on a domestic supply project as well as a potential LNG project. The Turkish government has voiced opposition to our drilling operations. However, the US and the European Union have expressed support for Cyprus' right to explore offshore for hydrocarbons in its exclusive economic zone.
Risks Although we will be able to incorporate major development project execution gained on the Aseng and Tamar projects to Leviathan or other LNG projects, such complex, costly projects as discussed above are 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 and Failure of our partners to fund their share of

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development costs or obtain project financing could result in delay or cancellation of future projects, thus limiting our growth and future cash flows.
See also Item 1A. Risk Factors - Our international operations may be adversely affected by economic and political developments and Our operations may be adversely affected by violent acts such as from 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

Our other international operations accounted for 2% of our total consolidated sales volumes for 2012 and 1% of total proved reserves at December 31, 2012.

Falkland Islands In August 2012, we entered into an agreement with Falkland Oil and Gas Limited (FOGL) to acquire an interest in FOGL's extensive license areas, consisting of approximately 10 million acres, gross, located south and east of the Falkland Islands. The Falkland Islands are located in the South Atlantic Ocean approximately 400 miles from the South America mainland. The agreement was approved by the Falkland Islands Government in October 2012.

Under the agreement we have farmed-in to the Northern and Southern Area Licenses for a 35% working interest. FOGL will continue as operator until we assume operatorship of the Northern Area License in March 2013 and the Southern Area License no later than March 2014.

Our financial contribution includes 60% of the costs of two commitment wells and a $25 million cash contribution paid in January 2013. We may also elect to participate in a discretionary exploration well, paying 45% of the costs in return for a 35% working interest. We expect to invest approximately $180 to $230 million over the next three years.

During fourth quarter 2012, FOGL drilled the Scotia exploration well, which reached its Cretaceous objective in November 2012 and encountered 40 feet of net pay. We are encouraged by the well results.  Although we did not see a substantial amount of the reservoir section, virtually all sandstones with significant porosity in and below the target contained hydrocarbons. We are currently evaluating the well results and have begun acquiring 3D seismic over the Northern and Southern Area licenses. The integration of these activities will allow us to assess the economic viability of this prospect. The Scotia well has been plugged in accordance with the regulations of the Falkland Islands Department of Mineral Resources, which require all exploration wells, including successful ones, to be plugged.

See Acquisition and Divestiture Activities - Entry into Falkland Islands Joint Venture and Item 1A. Risk Factors - Our entry into new exploration ventures in areas in which we have no prior experience subjects us to additional risks.

Nicaragua We continue to evaluate our undeveloped acreage and currently plan to spud our first exploration well (Paraiso), targeting a crude oil play, in the second half of 2013. A 3D seismic survey and further technical work have clarified this prospect and helped to decrease the risk. We are currently seeking a partner in this prospect, anticipating a working interest farmout by the time we spud the first exploration well.

China   We have been engaged in exploration and development activities in China since 1996 under the terms of a PSC, expiring in 2018. We are currently negotiating for an extension beyond 2018. 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.

North Sea   We have been conducting business in the North Sea (the Netherlands and the United Kingdom (UK)) since 1996. During 2012, we sold our 30% non-operated working interests in the Dumbarton and Lochranza fields, located in the UK sector of the North Sea. Also during the fourth quarter of 2012, the nearby Bligh well, a potential co-development candidate for our Selkirk discovery, was drilled. Bligh encountered hydrocarbons but disappointingly tight non-commercial reservoirs. Therefore, we determined that the Selkirk field was uneconomic for joint development and wrote it off to exploration expense. Our remaining North Sea assets are included in assets held for sale in our consolidated balance sheet as of December 31, 2012, and the North Sea geographical segment has been reported as discontinued operations in our consolidated statements of operations. See Item 8. Financial Statements and Supplementary Financial Data - Note 3.  Acquisitions and Divestitures.


Proved Reserves 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 Securities and Exchange Commission (SEC) definitions and guidance and prepared

19


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 selection of smaller fields, which combined represent over 80% of our proved 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 2012 reserves estimates.
 
Third-Party Reserves Audit   In each of the years 2012, 2011, and 2010, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2012 included a detailed review of eight of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 87% of US proved reserves and 98% of international proved reserves (93% of total proved reserves). The reserves audit for 2011 included a detailed review of 14 of our major fields and covered approximately 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.

In connection with the 2012 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, 2012, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with

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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 process results in the audit of each field representing more than 1% of total proved reserves, as well as a selection of smaller fields. 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, 2012, on a quantity basis, the NSAI field estimates ranged from 26 MMBoe or 18% above to 1 MMBoe or 2% 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, 2012 were, in the aggregate, approximately 48 MMBoe, or 4%.
 
Proved Undeveloped Reserves (PUDs)   As of December 31, 2012, our PUDs totaled 159 MMBbls of crude oil, condensate and NGLs and 3,382 Bcf of natural gas, for a total of 723 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, 2012:
 
372 MMBoe in the Tamar field, offshore Israel, which will begin converting to proved developed at first production, currently expected in second quarter 2013;
158 MMBoe in the DJ Basin, including Wattenberg, consisting of 958 horizontal Niobrara locations, which is equivalent to less than three years of drilling based on current plans;
106 MMBoe in the Marcellus Shale, consisting of 290 horizontal locations, which is equivalent to less than three years of drilling based on current plans;
74 MMBoe in Equatorial Guinea, 64% of which are in the Alba field with the remainder in the Alen field. The Alba reserves, which will be recovered from existing wells with a sanctioned compression project, will be reclassified to proved developed at start-up, currently expected in 2016. The Alen PUDs will be reclassified to proved developed at start-up, currently expected in 2013;
the above fields represent 98% of total PUDs. The remaining 2% is associated with ongoing developments in various areas scheduled in the next five years; and
PUDs include no material amounts which have remained undeveloped for five years or more.

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

recording of 135 MMBoe in the DJ Basin horizontal Niobrara program;
partially offset by negative revisions of 94 MMBoe in the DJ Basin due to our decision to terminate the legacy vertical drilling program and focus capital and drilling rigs on the horizontal development of the Niobrara;
recording of 51 MMBoe in the Marcellus Shale as a result of an ongoing development program with expansion into the wet gas area of the play;
recording of an additional 7 MMBoe at Tamar as a result of ongoing appraisal work, plus 1 MMBoe from other international areas;
conversion of 82 MMBoe into proved developed reserves, primarily related to ongoing development in the DJ Basin (19% of year-end 2011 PUDs converted) and Marcellus Shale (22% of year-end 2011 PUDs converted), the start-up of the Galapagos project in the deepwater Gulf of Mexico, and a pipeline pressure-reduction project in Equatorial Guinea;
the sale of 3 MMBoe from our non-core asset divestiture program;
positive revisions of 10 MMBoe, primarily due to increased recovery assumptions in the Marcellus Shale as a result of better than expected performance from existing wells; and
negative revisions of 7 MMBoe, primarily in the Marcellus Shale, due to changes in commodity prices.

Development Costs    Costs incurred to advance the development of PUDs were approximately $1.8 billion in 2012, $1.4 billion in 2011 (including $66 million non-cash costs related to an increase in our Aseng FPSO lease obligation), and $1.1 billion in 2010 (including $266 million non-cash costs related to an increase in our Aseng FPSO lease obligation). A significant portion

21


of costs incurred in 2012 related to our major development projects, horizontal Niobrara, Marcellus Shale, Alen and Tamar, which will be converted to proved developed reserves in future years.
 
Estimated future development costs relating to the development of PUDs are projected to be approximately $1.8 billion in 2013, $1.5 billion in 2014, and $1.1 billion in 2015. Estimated future development costs include capital spending on major development projects, some of which will take several years to complete. Proved undeveloped reserves related to major development projects will be reclassified to proved developed reserves when production commences.
 
Drilling Plans    All PUD drilling locations are scheduled to be drilled prior to the end of 2017.  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 2017.  Initial production from these PUDs is expected to begin during the years 2013 - 2017.
 
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, 2012, 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 (DOE). We file Form 23, including reserves and other information, with the EIA.



22


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, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
Wattenberg
 
32

 
194

 
13

 
$
89.41

 
$
2.67

 
$
35.50

 
$
4.45

Other US
 
17

 
244

 
3

 
104.30

 
2.57

 
34.92

 
8.00

Total US
 
49

 
438

 
16

 
94.69

 
2.61

 
35.36

 
6.04

Equatorial Guinea
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Alba Field (2)
 
12

 
235

 

 
107.08

 
0.27

 

 
2.79

Aseng Field
 
21

 

 

 
111.93

 

 

 
4.88

Total Equatorial Guinea
 
33

 
235

 

 
110.14

 
0.27

 

 
3.39

Mari-B Field (Israel)
 

 
101

 

 
 
 
4.85

 

 
3.23

China
 
4

 

 

 
114.54

 

 

 
10.33

Total Consolidated Operations
 
86

 
774

 
16

 
101.52

 
2.19

 
35.36

 
5.09

Equity Investee (3)
 
2

 

 
5

 
104.56

 
 
 
69.14

 
 
Total Continuing Operations
 
88

 
774

 
21

 
$
101.58

 
$
2.19

 
$
44.15

 
 
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

Aseng Field
 
2

 

 

 
106.87

 

 

 
9.08

Total Equatorial Guinea
 
14

 
245

 

 
107.57

 
0.27

 

 
2.64

Mari-B Field (Israel)
 

 
173

 

 

 
4.86

 

 
1.16

China
 
4

 

 

 
106.19

 

 

 
9.61

Total Consolidated Operations
 
56

 
806

 
15

 
99.17

 
3.00

 
48.35

 
4.47

Equity Investee (3)
 
2

 

 
5

 
108.76

 

 
72.71

 
 

Total Continuing Operations
 
58

 
806

 
20

 
$
99.46

 
$
3.00

 
$
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

Ecuador (5)
 

 
25

 

 

 

 

 

China
 
4

 

 

 
75.15

 

 

 
7.49

Total Consolidated Operations
 
54

 
781

 
14

 
75.76

 
2.98

 
41.21

 
4.39

Equity Investee (3)
 
2

 

 
5

 
77.98

 

 
53.68

 
 

Total Continuing Operations
 
56

 
781

 
19

 
$
75.83

 
$
2.98

 
$
44.90

 
 

 

23


(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.
(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 for 2010 from hedging activities. Average natural gas sales prices reflect a decrease of $0.01 per Mcf for 2010 from hedging activities. 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, 2012, our operated properties accounted for approximately 72% 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, 2012 was as follows: 
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
6,943

 
6,118.6

 
6,718

 
5,083.7

 
13,661

 
11,202.3

Equatorial Guinea
 
5

 
2.0

 
18

 
6.7

 
23

 
8.7

Israel
 

 

 
9

 
3.7

 
9

 
3.7

North Sea
 
9

 
1.2

 
9

 
1.1

 
18

 
2.3

China
 
27

 
15.4

 
1

 
0.6

 
28

 
16.0

Total
 
6,984

 
6,137.2

 
6,755

 
5,095.8

 
13,739

 
11,233.0

 
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.
 

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Developed and Undeveloped Acreage   Developed and undeveloped acreage (including both leases and concessions) held at December 31, 2012 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore (1)
 
1,808

 
1,186

 
2,207

 
1,512

Offshore
 
96

 
41

 
500

 
373

Total United States
 
1,904

 
1,227

 
2,707

 
1,885

International
 
 

 
 

 
 

 
 

Equatorial Guinea
 
285

 
119

 
180

 
80

Falkland Islands
 

 

 
9,921

 
3,472

Cameroon
 

 

 
1,084

 
542

Israel
 
124

 
58

 
1,333

 
581

Cyprus (2)
 

 

 
852

 
596

North Sea (3)
 
20

 
4

 
131

 
25

China
 
7

 
4

 

 

Sierra Leone
 

 

 
1,380

 
414

Nicaragua
 

 

 
1,855

 
1,855

India
 

 

 
694

 
347

Total International
 
436

 
185

 
17,430

 
7,912

Total
 
2,340

 
1,412

 
20,137

 
9,797

 
(1) 
Developed acres includes approximately 464,000 gross (214,000 net) 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.

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,
 
 
2013
 
2014
 
2015
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
 
 
 
 
Onshore US (1)
 
785

 
589

 
279

 
188

 
242

 
131

Deepwater Gulf of Mexico
 
42

 
20

 
29

 
20

 
42

 
37

Equatorial Guinea
 

 

 
307

 
137

 

 

Israel (2)
 
1,209

 
537

 

 

 

 

Cyprus (3)
 
852

 
596

 

 

 

 

Cameroon (4)
 
916

 
458

 
168

 
84

 

 

Total
 
3,804

 
2,200

 
783

 
429

 
284

 
168

 
(1) 
Represents acreage that will expire if no further action is taken to extend. Approximately 35% of the acreage is located in core areas where we currently expect to continue development activities and/or extend the lease terms.
(2) 
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.

25


(3) 
Represents acreage that will expire if no further action is taken to extend. We are currently planning to drill an appraisal well in 2013. The result of this well will assist us in the evaluation of our acreage.
(4) 
The acreage in Cameroon is comprised of our Tilapia PSC and YoYo mining concession. Pursuant to the Tilapia PSC, our first exploration period expires on July 6, 2013; however, we have the right to extend our acreage for two additional periods of two years each. Pursuant to our YoYo mining concession, development must commence prior to December 2014; we are actively engaged in negotiations to extend the term of the mining concession to 35 years.

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, 2012
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 
8.1

 
2.3

 
10.4

 
457.5

 

 
457.5

 
467.9

Equatorial Guinea
 

 

 

 
2.3

 

 
2.3

 
2.3

Cameroon
 

 
0.5

 
0.5

 

 

 

 
0.5

Israel
 

 

 

 
3.2

 

 
3.2

 
3.2

China
 

 

 

 
1.7

 

 
1.7

 
1.7

Total
 
8.1

 
2.8

 
10.9

 
464.7

 

 
464.7

 
475.6

Year Ended December 31, 2011
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 
9.6

 
3.7

 
13.3

 
641.2

 
4.0

 
645.2

 
658.5

Equatorial Guinea
 

 

 

 
0.5

 

 
0.5

 
0.5

Cameroon
 

 
0.5

 
0.5

 

 

 

 
0.5

Senegal/Guinea-Bissau
 

 
0.3

 
0.3

 

 

 

 
0.3

China
 

 

 

 
2.9

 

 
2.9

 
2.9

Total
 
9.6

 
4.5

 
14.1

 
644.6

 
4.0

 
648.6

 
662.7

Year Ended December 31, 2010
 
 

 
 

 
 

 
 

 
 

 
 

 
 

United States
 
4.8

 
1.9

 
6.7

 
510.6

 
1.0

 
511.6

 
518.3

Equatorial Guinea
 

 

 

 
2.0

 

 
2.0

 
2.0

Israel
 

 

 

 
1.0

 

 
1.0

 
1.0

North Sea
 

 

 

 
0.6

 

 
0.6

 
0.6

China
 

 

 

 
2.3

 

 
2.3

 
2.3

Total
 
4.8

 
1.9

 
6.7

 
516.5

 
1.0

 
517.5

 
524.2

 
In addition to the wells drilled and completed in 2012 included in the table above, wells that were in the process of drilling or completing at December 31, 2012 were as follows: 
 
 
Exploratory (1)
 
Development
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
13

 
8.1

 
172

 
88.0

 
185

 
96.1

Cameroon
 
1

 
0.5

 

 

 
1

 
0.5

Cyprus
 
1

 
0.7

 

 

 
1

 
0.7

Equatorial Guinea
 
8

 
4.0

 

 

 
8

 
4.0

Falkland Islands
 
1

 
0.4

 

 

 
1

 
0.4

Israel
 
6

 
2.5

 


 


 
6

 
2.5

Total
 
30

 
16.2

 
172

 
88.0

 
202

 
104.2


(1) 
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.

See Item 8. Financial Statements and Supplementary Financial Data - Note 7.  Capitalized Exploratory Well Costs for additional information on suspended exploratory wells.


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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 in water depths to 10,000 feet, 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 and rail cars 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, Noa and Pinnacles fields, and have contracted to sell natural gas from the the Tamar field, under long-term contracts. 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.
Mari-B GSPAs We currently sell natural gas from the Mari-B, Noa and Pinnacles fields to several customers, including Israel Electric Corporation (IEC), under long-term Gas Sale and Purchase Agreements (Mari-B GSPAs). Due to end-of-field life declines in production from these fields, we will not be able to meet all contractual delivery commitments under the Mari-B GSPAs with reserves from these fields.
In January 2012, we issued force majeure notices to certain customers. The Mari-B GSPAs have customary liability cap language that limits our financial exposure in the event we cannot fully deliver the contract quantities. Our liability is 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). To date, these adjustments have totaled approximately $13 million, net. These sales price adjustments did not have a material impact on our earnings or cash flows.
As of December 31, 2012, a total of 218 Bcf, gross, (102 Bcf, net) remained to be delivered under the Mari-B GSPAs. In the fourth quarter of 2012, we and our Mari-B partners signed an agreement with IEC. The terms of the agreement provide for delivery of up to 100,000 MMBtu/d, gross, (47,000 MMBtu/d, net) of natural gas under the first IEC sales contract, once the Tamar field begins flowing, until the total contract quantity is fulfilled and, at the same time, termination of the second IEC sales contract. We have executed similar agreements with most of the other Mari-B gas purchasers.
At December 31, 2012, our remaining Mari-B, Noa, and Pinnacles proved developed reserves totaled approximately 17 Bcf, net, and will be used to satisfy our share of the Mari-B GSPAs on a pro-rata basis until the Tamar field begins producing. We expect that approximately 30 Bcf, net, of our Tamar proved reserves will be used to satisfy our share of contract quantities that remain to be delivered under the Mari-B GSPAs, as impacted by the recent agreements, when the fields cease producing. The majority of the quantities remaining under the Mari-B GSPAs are expected to be delivered over a three year period with one minor commitment extending over a 10-year period.
Tamar GSPAs As of December 31, 2012, we and our Tamar partners have entered into Gas Sale and Purchase Agreements (Tamar GSPAs) with the IEC and numerous other Israeli purchasers, including independent power producers, cogeneration

27


facilities and industrial companies, for the sale of natural gas from the Tamar field. The Israeli government has approved the Tamar GSPAs.
The Tamar GSPAs include the following:
sale of approximately 2.7 Tcf (approximately 1.0 Tcf net to us) of natural gas to IEC over an approximate 15-year period. IEC has the option to increase this amount to 3.5 Tcf (approximately 1.3 net to us), under certain conditions;
sale of approximately 2.5 Tcf (approximately 0.9 Tcf net to us) of natural gas to additional customers. Most contracts provide for the sale of natural gas over a 15 to 17 year period. Some of the contracts provide for increase or reduction in total quantities and some are interruptible during certain contract periods; and
sales prices based on an initial base price subject to price indexation over the life of the contract and with a floor. The IEC contract also provides for price reopeners in the eighth and eleventh years with limits on the increase/decrease from the contractual price.
Under the Tamar GSPAs, we and our partners have a financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and 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 under certain circumstances and with a cap (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.
At December 31, 2012, we have recorded 2.2 Tcf, net, of PUD reserves for the Tamar field. We expect to begin reclassifying these PUD reserves to proved developed at first production, currently expected in second quarter 2013. See International - Eastern Mediterranean (Israel and Cyprus) - Tamar Natural Gas Project.

Significant Purchaser   Glencore Energy was the largest single non-affiliated purchaser of 2012 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 31% of 2012 total oil, gas and NGL sales, or 39% of 2012 crude oil sales. Shell Trading (US) Company and Shell International Trading and Shipping Limited (collectively, Shell) purchased crude oil and condensate domestically from the deepwater Gulf of Mexico and the Wattenberg area and internationally from the North Sea. Sales to Shell accounted for 14% of 2012 total oil, gas and NGL sales, or 17% of crude oil sales. No other single non-affiliated purchaser accounted for 10% or more of crude oil and natural gas sales in 2012. 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 2012 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. As a result of hedging, near-term cash flow volatility is reduced, which allows us to plan our financial commitments and support our capital investment programs.
Our practice is to hedge up to 50% of our forecasted domestic natural gas production and up to 50% of our total forecasted domestic and international crude oil production, for the current year plus two additional calendar years. We strive to maintain strong governance of our hedging program, including oversight by our Board of Directors. 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 federal, state, and local levels in the US, and internationally. 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

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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 Israeli Antitrust Commission which reviews Israel's domestic natural gas sales and ownership in offshore blocks and leases;
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;
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;
the Petroleum Directorate which regulates our exploration activities offshore Sierra Leone; and
the Department of Mineral Resources which regulates our exploration activities offshore the Falkland Islands.
Examples of other laws affecting our international operations are the Israeli Petroleum Profits Taxation Law, 2011, which imposes additional income tax on oil and gas production, and the UK Finance Bill 2011, which increased the rate of the Supplementary Charge levied on oil and gas income. Under the Israeli Petroleum Profits Taxation Law, 2011, the depletion allowance was abolished, and a levy at an initial rate of 20% was imposed on profits from oil and gas. The levy gradually rises to 50%, depending on the levy coefficient (the R-Factor). The R-Factor refers to the percentage of the amount invested in the exploration, development and establishment of the project, so that the 20% rate is imposed only after a recovery of 150% of the amount invested (R-Factor of 1.5) and scales linearly up to a maximum of 50% after a recovery of 230% of the amount invested (R-Factor of 2.3). The rate of royalties paid to the State of Israel remained unchanged. Also affecting our operations in Israel is the Law for Change in the Tax Burden (Amendments to Legislation), 2011 (the 2011 Tax Act). As from 2012, the 2011 Tax Act eliminates, inter alia, a previously enacted progressive reduction in the rate of corporate tax rate, and increases the corporate tax rate to 25%.
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), which under laws such as the Federal Land Policy and Management Act, Endangered Species Act, National Environmental Policy Act and Outer Continental Shelf Lands Act, have certain authority over our operations on federal lands, particularly in the Rocky Mountains and deepwater Gulf of Mexico;
the Office of Natural Resources Revenue, which under the Federal Oil and Gas Royalty Management Act of 1982 has certain authority over our payment of royalties, rentals, bonuses, fines, penalties, assessments, and other revenue;
the US Environmental Protection Agency (EPA) and the Occupational Safety and Health Administration (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, the Safe Drinking Water Act, and the Occupational Safety and Health Act have certain authority over environmental, health and safety matters affecting our operations;
the US Fish and Wildlife Service, which under the Endangered Species Act has authority over activities that may result in the take of an endangered species or its habitat;
the US Army Corps of Engineers, which under the Clean Water Act has authority to regulate the construction of structures involving the fill of certain waters and wetlands subject to federal jurisdiction, including well pads, pipelines, and roads;
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.

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Various state and federal statutes prohibit certain actions that adversely affect endangered or threatened species and their habitat, wetlands, migratory birds, and natural resources. Where the taking or harm of such species occurs or may occur, or where damages to wetlands or natural resources may occur, the government or private parties may act to prevent oil and natural gas exploration activities. A federal or state agency could order a complete halt to drilling activities in certain locations or during certain seasons when such activities could result in a serious adverse effect upon a protected species. The presence of a protected species in areas where we operate could adversely affect future production from those areas.
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, beginning in 2012 for 2011 emissions, 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 are subject to the Subpart W reporting requirements.
On April 18, 2012, the EPA issued regulations under the New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants. The new rules are related to emissions associated with crude oil and natural gas production, including natural gas wells that are hydraulically fractured. The required technologies and processes, while reducing emissions, will also enable companies to collect additional natural gas that can be sold. The EPA's final standards also address emissions from storage tanks and other equipment. The final rules establish a phase-in period that will ensure that manufacturers have time to make and broadly distribute the required emissions reduction technology.  During the first phase, until January 2015, owners and operators must either flare their emissions or use emissions reduction technology called “green completions,” technologies that are already widely deployed at wells. In 2015, all newly fractured wells will be required to use green completions. The EPA's final rules have minimal impact on our business. The reduction of greenhouse gas emissions (GHG) is already one of our priorities and we have been working to improve our methods to reduce GHGs through operational and business practices.  We use green completions or flaring on a number of our wells to comply with Colorado Oil and Gas Conservation Commission (COGCC) rules.  Additionally we've undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture gas that would otherwise be flared on a substantial number of our tank batteries.
Most of the states within which we operate have separate agencies with authority to regulate related operational and environmental matters.  
Colorado 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 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.
In February 2013, the COGCC is expected to approve and implement new setback rules for oil and gas wells and production facilities located in close proximity to occupied buildings. If the new setback rules are approved, the current COGCC setback distances of 150 feet in rural areas and 350 feet in high density urban areas will be increased to a uniform 500 feet statewide setback from occupied buildings and a uniform 1,000 feet statewide setback from high occupancy building units. The new setback rules would also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. The new rules would also require advance notice to surface owners, the owners of occupied buildings and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment as well as expanded outreach and communication efforts by an operator.

The COGCC also approved two new rules making Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. The new statewide rule requires sampling of up to four water wells within a half mile radius of a new oil and gas well before drilling, between six and 12 months after completion, and between five and six years after completion. The revised rule for the GWA requires operators to sample only one water well per quarter governmental section before drilling and between six to 12 months after completion.

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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.
Pennsylvania On February 14, 2012, Governor Tom Corbett of Pennsylvania signed into law what is known as Act 13 of 2012 (Act 13). Act 13 represents the first comprehensive legislation regarding the development of the Marcellus Shale in Pennsylvania. Act 13, among other things, enacted stronger environmental standards and established impact fees, which in 2012 equaled $50,000 for each horizontal Marcellus Shale well. Act 13 also increased the notice distance of unconventional well permit applications from 1,000 feet to 3,000 feet, and extended the setback distance for unconventional wells from 200 feet to 500 feet. The statute also increased the distance and duration of presumed liability for water pollution to 2,500 feet from a well site and twelve months after well completion, drilling, stimulation, or alteration. In addition, Act 13 imposed spill prevention requirements applicable to well site construction, wastewater transportation, and gathering lines. These requirements may result in increased costs and lower rates of return for our Marcellus Shale development project.

In March 2012, seven municipalities filed suit against Act 13's statewide zoning provisions, claiming that Act 13 violated the state constitution. On July 26, 2012, the Pennsylvania Commonwealth Court declared the statewide zoning provisions in Act 13 unconstitutional, null, void and unenforceable. The Court also struck down the provision of the law that required the Pennsylvania Department of Environmental Protection to grant waivers to the setback requirements in Pennsylvania's Oil and Gas Act. This decision was appealed to the Pennsylvania Supreme Court and arguments were presented on October 18, 2012. The decision from the Supreme Court is still pending, but a ruling upholding the lower court's decision could make it more difficult to develop our Marcellus acreage in some municipalities within Pennsylvania.

NETL Study The US Department of Energy's National Energy Technology Laboratory (NETL) is conducting a comprehensive assessment of the environmental effects of shale gas production at two industry-provided Marcellus Shale test sites in southwestern Pennsylvania. Goals include:
documentation of environmental changes that are coincident with shale gas production;
development of technology or management practices that mitigate undesigned environmental changes; and
development of monitoring technologies to (1) assess the impact of shale gas production on air quality and (2)determine if zonal isolation between producing formations and drinking water aquifers is maintained after hydraulic fracturing.
We will monitor the results of the NETL study in order to assess any potential impact on our onshore US development programs.
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.
Israeli Interministerial Committee In 2011, the Interministerial Committee to Examine Government Policy Regarding the Natural Gas Industry in Israel (the Committee) was charged with the task of proposing a government policy for developing the natural gas economy. Objectives include the following:
ensuring energy security in the economy;
providing a framework for substantial resource exports;
designating a certain percentage of production from each field for domestic natural gas demand;
maintaining competition in the different sectors of the local economy;
maximizing economic and political benefits; and
leveraging environmental advantages with respect to the use of natural gas.
The Committee was also asked to examine, among other items, the desired policy to maintain reserves to supply local demand and export of natural gas. In September 2012, the Committee issued its final recommendations. In its report, the Committee stated that permitting export of natural gas does not prevent, but rather promotes the ensuring of the needs of domestic users and works to encourage development of natural gas-based domestic industry. The recommendations included, among others, the following points:
as a rule, all reservoirs should be charged with supplying a certain percentage of natural gas to the local economy, with minimum requirements based on reservoir size (minimum of 25%-50%). The minimum supply obligations will not apply for reservoirs under a certain size (25 BCM) but the reservoirs will be required to be connected to the domestic

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market. The recommendations allow for a lease in a developed reservoir to exchange its export quota against an "obligation to supply to the domestic market" which applies to any other leaseholder which submitted a development plan so long as approval therefor is given by the Petroleum Commissioner in the Ministry of Energy and Water Resources and by the Antitrust Authority;
a determination that the quantity of natural gas that should be guaranteed in favor of the local economy should be 450 BCM and that the quantity should be updated in five years;
the export of natural gas should be permitted as long as the quantity from all reservoirs does not exceed 500 BCM, which amount may be reassessed;
regulatory approval required for export, with export licenses eligible for periods up to 25 years;
there should be an absolute preference for the export of natural gas from a facility in an area under Israeli control, including Israel's exclusive economic zone, although further study of various export means (such as export from a foreign area governed by bilateral agreement) and statutory feasibility is necessary; and
steps should be taken to increase competition in the natural gas market.
 
We are participating in the process and monitoring the impact of the Committee's recommendations. However, at this time, we cannot predict the ultimate outcome of the Committee's recommendations or the possible impact any resulting laws or regulations could have on our business. Certain changes in Israel's market, fiscal, and/or regulatory regimes occurring as a result of the Committee's recommendations could delay or reduce the profitability of our Tamar and/or Leviathan development projects and render future exploration and/or development projects uneconomic.
Impact of Dodd-Frank Act Derivatives Regulation The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act), which was passed by Congress and signed into law in July 2010, contains significant derivatives regulation, including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for such transactions. The Dodd-Frank Act provides for a potential exception from these clearing and collateral requirements for commercial end-users, such as us, and it includes a number of defined terms used in determining how this exception applies to particular derivative transactions and the parties to those transactions. As required by the Dodd-Frank Act, the Commodities Futures and Trading Commission (CFTC) has promulgated numerous rules to define these terms.
We have been evaluating the provisions of the CFTC's final rules and assessing their impact on our commodity hedging program. At this time, we believe that we will be able to satisfy the requirements for the commercial end-user clearing exception and continue to engage in transactions which hedge commercial risk and are free of mandated clearing requirements.
It is possible that the CFTC, in conjunction with prudential regulators, may mandate that financial counterparties entering into swap transactions with end-users must do so with credit support agreements in place, which could result in negotiated credit thresholds above which an end-user must post collateral. If this should occur, we intend to manage our credit relationships to minimize collateral requirements.
The CFTC's final rules will also have an impact on our hedging counterparties. For example, our bank counterparties will be required to post collateral and assume compliance burdens resulting in additional costs. We expect that much of the increased costs will be passed on to us, thereby decreasing the relative effectiveness of our hedges and our profitability. To the extent we incur increased costs or are required to post collateral in periods of rising commodity prices, there could be a corresponding decrease in amounts available for our capital investment program. See Item 1A. Risk Factors - Derivatives regulation included in current or proposed financial legislation and rulemaking could impede our ability to manage business and financial risks by restricting our use of derivative instruments as hedges against fluctuating commodity prices and interest rates.
Impact of Dodd-Frank Act Section 1504 Section 1504 of the Dodd-Frank Act required the SEC to issue rules requiring resource extraction issuers to include in an annual report information relating to any payment made by the issuer, a subsidiary of the issuer, or an entity under the control of the issuer, to a foreign government or the federal government for the purpose of the commercial development of oil, natural gas, or minerals. On August 22, 2012, the SEC issued a final rule, Disclosure of Payments by Resource Extraction Issuers (Rule). The Rule requires resource extraction issuers, such as us, to provide information about the type and total amount of payments made for each project related to the commercial development of oil, natural gas, or minerals, and the type and total amount of payments made to each government. The first report is due May 30, 2014.
In October 2012, the U.S. Chamber of Commerce, American Petroleum Institute, Independent Petroleum Association of America, and National Foreign Trade Council filed a lawsuit against the SEC in the U.S. Court of Appeals for the District of Columbia Circuit. The petitioners argued that the Rule is “arbitrary and capricious” within the meaning of the Administrative Procedure Act and that the Rule and statute violate the First Amendment. Briefs have been submitted. Oral arguments are not yet scheduled.
See Item 1A. Risk Factors - Disclosure of certain operating information as required by Section 1504 of the Dodd-Frank Act could have a negative impact on our operations.

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See also Item 1A. Risk Factors - Our operations may be adversely affected by changes in the fiscal regimes and government policies and regulation of oil and gas development in the countries in which we operate for a discussion of the American Taxpayer Relief Act of 2012.
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, facility siting and construction, 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, is 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 claims that hydraulic fracturing may contaminate groundwater, reduce air quality or cause earthquakes. Hydraulic fracturing requires the use and disposal of water, and public concern has been growing over its possible effects on drinking water supplies, as well as the adequacy of supply.
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. 
We strive to procure non-hydrologic water (water that is not connected to a natural surface stream); approximately 80% of our water is from non-tributary sources, such as deep ground water. 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 engage in recycling efforts. 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

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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 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.
During 2012, the BLM proposed regulations governing hydraulic fracturing on federal lands. The regulations would require: (1) public disclosure of chemicals used in hydraulic fracturing operations; (2) assurances on well-bore integrity to verify that fluids used in wells during fracturing operations are not escaping; and (3) confirmation of a water management plan in place for handling fracturing fluids that flow back to the surface. On January 21, 2013, the BLM announced that it was withdrawing its proposed regulations and would reissue a new set of proposed regulations regarding hydraulic fracturing later in 2013.
During 2012, the EPA proposed new guidelines under the Safe Drinking Water Act regarding the issuance of permits for the use of diesel fuel as a component in hydraulic fracturing activities. The draft guidance outlines for EPA permit writers, where EPA is the permitting authority, requirements for diesel fuels used for hydraulic fracturing wells, technical recommendations for permitting those wells, and a description of diesel fuels for EPA underground injection control permitting.
The EPA is currently studying the potential impacts of hydraulic fracturing on drinking water resources. Results are expected to be released in a draft for public and peer review in 2014. 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. 
In June 2012, OSHA and the National Institute of Occupational Safety and Health (NIOSH) issued a joint hazard alert for workers who use silica (sand) in hydraulic fracturing activities. OSHA is working with industry and other government agencies to review existing regulations for applicability to hydraulic fracturing.
In 2012, the City of Longmont, Colorado voted to ban hydraulic fracturing activities within city limits. Subsequently, the State of Colorado, through the COGCC, sued the City of Longmont in Boulder County District Court to set aside a city ordinance that promulgated stricter oil and gas rules than the COGCC Rules asserting that portions of these rules are preempted by State statutes and COGCC rules. The Colorado Oil and Gas Association (COGA) moved to intervene in this action and intervention was granted. COGA also separately sued the City of Longmont claiming that the resolution is a taking of the mineral property rights and an improper regulatory impairment of such rights, that it is effectively an illegal ban on drilling, and otherwise asserting that the ban must be set aside since it conflicts with Colorado state law allowing the practice.   
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. In 2012, through legislation known as Act 13, Pennsylvania established a requirement that operators submit information regarding hydraulic fracturing chemicals to FracFocus.org. 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 disclosure information on FracFocus.org for all onshore US areas in which we operate. 

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Additional Information    See: 
Items 1. and 2. Business and Properties – Regulations;
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 – Liquidity and Capital Resources – Risk and Insurance Program.
Undeveloped Oil and Gas Leases Oil and gas exploration is a lengthy process of obtaining data, evaluating, and de-risking prospects, and it takes time to develop resources in a responsible manner. The period of time from lease acquisition to discovery can take many years of continuous effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the federal government. It may take years for us to assemble enough acreage to cover the areal extent of a prospect that we wish to explore.
Once the acreage position is assembled, we obtain seismic data either through purchase of available data or by contracting for seismic services. Our exploration staff then begin a lengthy process of analyzing the seismic and other data in order to identify a potential optimal location for drilling an initial exploratory well. Once we decide to drill an exploratory well, we must obtain permits and locate a drilling rig with the specifications for the depth and pressure situation in which we will drill.
For example, several years ago, we wanted to leverage our expertise in the Wattenberg area to open a new opportunity in Northern Colorado. We began acquiring acreage spanning an area from the edge of the GWA to the Wyoming border. It took over two years to assemble enough acreage through acquisition and leasing to have a significant enough acreage position to warrant data collection. Once the acreage position had been established, we conducted an extensive 3D seismic program and obtained other data as well, which our exploration staff analyzed and used to plan an initial drilling program.
After drilling an exploratory well, we must integrate data, such as core samples and well logs, obtained from the drilling process with our seismic and other data to determine if we have discovered hydrocarbons.
If there is a discovery, we may need to obtain additional data and/or drill appraisal wells in order to estimate the extent of the reservoir and the volume of resources that could potentially be recovered, and make an investment decision. Appraisal or development drilling requires additional time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies. Due to the current high level of drilling activity, drilling rigs and hydraulic fracturing crews are in high demand, and there could be substantial delays as we wait for rigs or crews to become available.
In Northern Colorado, our data collection efforts resulted in a successful initial drilling program. Due to the success of our first wells, we have continued the Northern Colorado drilling program and, in 2012, we drilled 25 development wells.
We strive to maintain an appropriate inventory of onshore and offshore exploration prospects suitable to our experience as an operator, financial resources, and current development timeline.
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 four components that are all primarily in the business of crude oil, natural gas and NGL exploration, development and production: United States,

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West Africa, Eastern Mediterranean, and Other International and Corporate. See Item 8. Financial Statements and Supplementary Data – Note 17.  Segment Information
Employees 
Our total number of employees increased 17%, from 1,876 at December 31, 2011 to 2,190 at December 31, 2012, in support of our major development and exploration projects. The 2012 year-end employee count includes 203 foreign nationals working as employees in 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; Greeley, Colorado; and Canonsburg, Pennsylvania; and in China, Cameroon, 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.
Butler vs. Powers On September 7, 2011, an intermediate appellate court (Superior Court) in Pennsylvania issued an opinion in Butler v. Powers regarding the interpretation 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 raised by the case 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 shale gas is contained inside unconventional shale rock. An appeal of the decision was subsequently filed with the Pennsylvania Supreme Court, which decided to hear the appeal. Written and oral arguments in the case have been presented and the parties are awaiting the decision of the 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 and our Marcellus Shale joint venture operations. 
Title Defects Subsequent to a lease or fee interest acquisition, such as our Marcellus Shale acquisition in 2011, the buyer usually has a period of time in which to examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement, which may provide for arbitration between the buyer and seller. We continue to examine some of our Marcellus Shale leases and fee interests for potential title defects. Options to address uncured title defects include a reduction in the remaining amount of the CONSOL Carried Cost Obligation, an indemnity agreement, or the transfer of additional interests.
Conflicts with Surface Rights Mineral rights are property rights that confer to the holder the right to use land surface that is reasonably necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently pending in several states. In several cases, owners of surface rights are suing to prevent companies from using their land surface to drill horizontal wells to explore for or produce natural gas from neighboring mineral tracts. If a plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well pads and/or limit the length of horizontal wells drilled from a pad.
Risk Management
The oil and gas business is subject to many significant risks, including operational, strategic, financial and compliance/regulatory risks. We strive to maintain a proactive enterprise risk management (ERM) process to plan, organize, and control our activities in a manner which is intended to minimize the effects of risk on our capital, cash flows and earnings. ERM expands our process to include risks associated with accidental losses, as well as financial, strategic, operational, regulatory, political, and other risks.
Our ERM process is designed to operate in an annual cycle, integrated with our long range plans, and supportive of our capital structure planning. Elements include, among others, a robust global compliance program, credit risk management, a commodity hedging program to reduce the impacts of commodity price volatility, an insurance program to protect against disruptions in our cash flows, and cash flow at risk (CFAR) analysis. We benchmark our program against our peers and other global organizations. See Item 1A. Risk Factors for a discussion of specific risks we face in our business.

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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. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. 
If any of the events described below occur, our business, financial condition, results of operations, liquidity or access to the capital markets could be materially adversely affected. In addition, the current global economic and political environment intensifies many of these risks. 
Crude oil, natural gas, and NGL prices are volatile and a reduction in these prices could adversely affect our results of operations, our liquidity, 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, natural gas, and NGL production. Historically, the markets for crude oil, natural gas, and NGLs have been volatile and are likely to continue to be volatile in the future. For example, high and low daily average settlement prices for prompt month contracts for crude oil and natural gas during 2012 were as follows:
 
 
Daily Average Settlement Price for Prompt Month Contracts
 
 
High
 
Low
Year Ended December 31, 2012
 
 
 
 
NYMEX
 
 
 
 
   Crude Oil - WTI (Per Bbl)
 
$
109.77

 
$
77.69

   Natural Gas - HH (Per MMBtu)
 
3.90

 
1.91

Brent
 
 
 
 
   Crude Oil (Per Bbl)
 
126.22

 
89.23

Prices for our NGL production are determined at two primary market centers, Conway and Mt. Belvieu. For the year ended December 31, 2012, our consolidated net realized NGL prices were approximately 37% of consolidated net realized crude oil prices and tended to track the volatility of NYMEX WTI.
The markets and prices for crude oil, natural gas, and NGLs depend on factors beyond our control, factors including, among others:
    economic factors impacting global gross domestic product growth rates;
    global demand for crude oil, natural gas and NGLs;
    global factors impacting supply quantities of crude oil, natural gas and NGLs;
OPEC spare capacity relative to global crude oil supply;
    further application of horizontal drilling techniques which could increase production and significantly impact both domestic and global supplies of crude oil and natural gas;
ability to develop natural gas in shale or crude oil in tight formations relatively inexpensively which could increase the supply of natural gas or crude oil;
    the potential expansion of the global LNG market, including potential exports from the US;
    actions taken by foreign hydrocarbon-producing nations;
    political conditions and events (including instability or armed conflict) in hydrocarbon-producing regions;

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the existence of government imposed price and or product subsidies;
the price and availability of alternative fuels, including coal, solar, wind, nuclear energy and biofuels;
the long-term impact on the crude oil market of the use of natural gas as an alternative fuel for road transportation;
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;
impact of conservation efforts on the ability to access government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Declines in commodity prices or lack of natural gas storage 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, natural gas, and NGLs 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 reduced ability to develop our reserves;
limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations; and
limit our access to sources of capital, such as equity and long-term debt.
In addition, lower commodity prices, including declines in the forward commodity price curves, may result in the following:
asset impairment charges resulting from reductions in the carrying values of our oil and gas properties at the date of assessment, such as occurred in 2012, 2011, and 2010;
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, limitation of our growth and negative impact on our operating results, liquidity and financial position.
We currently have an extensive inventory of major development projects in various stages of development. Gunflint, Big Bend, Leviathan, Cyprus, Carla and Diega are being appraised and, as such, not yet sanctioned, and it will take several years before first production is achieved. Some projects, such as crude oil and natural gas projects offshore West Africa and the Eastern Mediterranean, entail significant technical and other 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. Our Leviathan project also includes potential LNG infrastructure. In addition, we have expanded our horizontal drilling programs in the Niobrara formation and Marcellus Shale.
This level of development activity requires significant effort from our management and technical personnel and places additional requirements on our financial resources and internal financial controls. In addition, we have increased dependency on third-party technology and service providers and other supply chain participants for these complex projects. We may not be able to fully execute these projects due to:
inability to attract and/or retain sufficient quantity of personnel with the skills required to bring these complex projects to production on schedule and on budget;
significant delays in delivery of essential items or performance of services, cost overruns, supplier insolvency, or other critical supply failure could adversely affect project development;
lack of government approval for projects;
civil disturbances, anti-development activities, legal challenges or other interruptions which could prevent access; and
drilling hazards or accidents or natural disasters.
 
We may not be able to compensate for, or fully mitigate, these risks.
Our international operations may be adversely affected by economic and political developments.
We have significant international operations, with approximately 40% of our 2012 total consolidated sales volumes coming from international areas. This will be increasing as major development projects offshore West Africa and the Eastern Mediterranean begin producing in 2013. 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:

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renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of recommendations of Israel's Interministerial Committee to Examine Government Policy on Israel's Natural Gas Economy (Interministerial Committee), or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can result in an increase in the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by foreign hydrocarbon-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 the Turkish government in Ankara objected to exploratory activities conducted offshore the Republic of Cyprus;
changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident or other 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;
international monetary fluctuations and changes in the relative value of the US dollar as compared with the currencies of other countries in which we conduct business, such as Israel; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Certain of these risks could be intensified by large crude oil or natural gas discoveries in areas where we are currently conducting exploration activities, such as in the Eastern Mediterranean, offshore Nicaragua, or the Falkland Islands. Large discoveries, such as ours in the Levant Basin, may have impacts on global natural gas supplies.
Such political and economic developments as mentioned above could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
Our operations may be adversely affected by changes in the fiscal regimes and government policies and regulation of oil and gas development in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing royalties, taxes, resource access, or level of government participation in oil and gas projects. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government take, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, the Petroleum Profits Taxation Law, 2011, imposed additional income tax on oil and gas production in Israel. A large portion of our production comes from Equatorial Guinea; therefore, changes in its fiscal regime could have a significant impact on our operations. In addition, we cannot predict how government agencies or courts will interpret existing tax laws and regulations or the effect such interpretations could have on our business.
Many countries are currently experiencing fiscal problems and sustained structural government budget deficits and lower tax revenues triggered by the lingering effects of the global economic crisis of 2008, associated recession and current slower economic growth rates. Higher unemployment and slower growth rates, coupled with a reduced tax base, have resulted in reduced government revenues, while government expenditures continue to grow due to the costs of entitlements, subsidies and economic stimulus programs. Many countries have generated significant budget deficits and sovereign debt levels with some approaching insolvency. Demands on certain governments to undertake austerity measures in response to the European debt crisis have resulted in increased social unrest. In addition, certain non-governmental organizations are promoting "tax fairness", "fair share" payments, and income redistribution. Regulations enacted to achieve "tax fairness" or income redistribution could result in increased tax burdens on individuals or corporations