10-K 1 nbl-20131231x10k.htm 10-K NBL-2013.12.31-10K
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, 2013
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)
1001 Noble Energy Way
 
 
Houston, Texas
 
77070
(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, 2013: $21.5 billion.
Number of shares of Common Stock outstanding as of December 31, 2013: 359,905,771.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2014 Annual Meeting of Stockholders to be held on April 22, 2014, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2013, 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.





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.
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 in 1932, 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 find and deliver energy through crude oil and natural gas exploration and production while embracing our responsibility to 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, respect our environment and care for our people and the communities where we operate.
We aim to achieve sustainable growth in value and cash flow through exploration success and the development of a high-quality, diversified portfolio of assets with investment flexibility between: onshore unconventional developments and offshore organic exploration leading to major development projects; US and international projects; and production mix among crude oil, natural gas and natural gas liquids (NGLs). Exploration success, along with development 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 well diversified, growing portfolio. During 2013, we spent over $3 billion in oil and gas exploration and development activities in the US, and approximately $1 billion in international locations.
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 effective major development project execution. During 2013, two major offshore development projects, Tamar, offshore Israel, and Alen, offshore Equatorial Guinea, began production. Our ability to deliver major development projects on schedule and within budget has provided a competitive and financial advantage in the industry.
Onshore US assets provide a stable base of production along with high return, low risk development programs that deliver growth and accommodate flexible capital spending 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 cycle offshore development projects, while requiring multi-year capital investment, are expected to offer attractive financial returns, and sustained production and cash flow.
We have operations in five core areas:
 
These five core areas provide:
l the DJ Basin (onshore US);
 
l the majority of our crude oil, natural gas and NGL production;
l the Marcellus Shale (onshore US);
 
l visible growth from major development projects; and
l the deepwater Gulf of Mexico (offshore US);
 
l numerous exploration opportunities.
l offshore West Africa; and
 
 
l offshore Eastern Mediterranean.
 
 
Our growth is supported by a strong balance sheet and liquidity levels. We strive to deliver competitive returns and a growing dividend. Our annual cash dividends have increased 67% in the last five years, from 33 cents per share in 2008 to 55 cents per share in 2013 (as adjusted for the 2-for-1 stock split during the second quarter of 2013). 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 2009-2013.

2


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 continue to advance 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, front-end engineering and design, development drilling, construction and production. We currently have projects in all phases of the development cycle with some contributing production growth in 2013. Although these projects will require significant capital investments over the next several years, they typically offer long-life, sustained cash flows and attractive financial returns. Our current major development projects resulting from exploration success and strategic acquisitions include the following:
Sanctioned(1) Projects
Unsanctioned Projects
 
 
 
 
·
Horizontal Niobrara (onshore US) (2)
·
Leviathan (offshore Israel)
·
Marcellus Shale (onshore US) (2)
·
Cyprus (offshore Cyprus)
·
Gunflint (deepwater Gulf of Mexico)
·
Diega and Carla (offshore Equatorial Guinea)
·
Big Bend (deepwater Gulf of Mexico)
·
Dantzler (deepwater Gulf of Mexico)
·
Tamar Expansion (offshore Israel)
 
 
·
Tamar Southwest (offshore Israel)
 
 
(1) 
Final investment decision has been made.
(2) 
Represents multiple ongoing development projects. The Keota plant and East Pony Integrated Development Plan (IDP) in the Horizontal Niobrara were sanctioned during 2013. We are currently evaluating additional onshore US IDPs for future sanction.
These projects are discussed in more detail in the sections below. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – Major Development Project Inventory.
Proved Oil and Gas Reserves    Proved reserves at December 31, 2013 were as follows:
 
Summary of 2013 Oil and Gas Reserves as of Fiscal-Year End
Based on Average 2013 Fiscal-Year Prices 
 
 
December 31, 2013
 
 
Proved Reserves
 
 
Crude Oil,
Condensate
& NGLs
 
Natural Gas
 
Total
Reserves Category
 
(MMBbls)
 
(Bcf)
 
(MMBoe) (1)
Proved Developed
 
 
 
 
 
 
United States
 
147

 
1,212

 
349

Equatorial Guinea
 
75

 
457

 
151

Israel
 
3

 
2,046

 
344

Other International (2)
 
5

 
2

 
5

Total Proved Developed Reserves
 
230

 
3,717

 
849

Proved Undeveloped
 
 

 
 

 
 

United States
 
185

 
1,444

 
425

Equatorial Guinea
 
19

 
234

 
58

Israel
 

 
433

 
72

Other International (2)
 
2

 

 
2

Total Proved Undeveloped Reserves
 
206

 
2,111

 
557

Total Proved Reserves
 
436

 
5,828

 
1,406

 
(1) 
Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude 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 crude oil equivalent for natural gas is significantly less than the price for a barrel of crude oil. The price for a barrel of NGL is also less than the price for a barrel of crude oil. See Item 6. Selected Financial Data.
(2) 
Other international includes the North Sea and China.

3


Total proved reserves as of December 31, 2013 were approximately 1,406 MMBoe, a 19% increase from 2012. Our proved reserves are 55% US and 45% international. The proved reserves mix is 31% global liquids (crude oil and NGLs), 38% international natural gas, and 31% 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 numerous areas of interest. These activities include geophysical and geological evaluation, analysis of commercial, regulatory and political risk 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. These assets 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, emanating from proprietary seismic data and operational expertise, and which we believe will generate superior returns. We have had substantial exploration success onshore US, 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 exploration program. During 2013, we advanced our exploration activities in the following new venture areas: onshore US in northeast Nevada, offshore Falkland Islands, offshore Nicaragua, and offshore Sierra Leone.
Appraisal, Development and Production Activities   Our discoveries and strategic acquisitions in recent years have provided us with numerous appraisal, development, and production opportunities, as demonstrated in our growing inventory of major development projects.  In 2013, we commenced natural gas production from the Tamar field, offshore Israel, followed by the start up of Alen, a natural gas and condensate field, offshore Equatorial Guinea. Additionally, we continued to make significant progress on our ongoing onshore US and other major development projects.
Acquisition and Divestiture Activities   We maintain an ongoing portfolio management program. Accordingly, we may engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities owning the assets. We may also periodically divest non-core, non-strategic assets.
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-value and high-growth areas. The program has generated combined net proceeds of approximately $1.4 billion during the last two years, including $206 million during 2013. The proceeds from divestitures provide additional flexibility in the implementation of our international and deepwater Gulf of Mexico exploration and development programs and our horizontal drilling activities in the DJ Basin and Marcellus Shale.
During 2013, we sold onshore US crude oil and natural gas properties located in Kansas, Oklahoma, the Gulf Coast, New Mexico and Wyoming, and non-operated working interests in the North Sea.
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 2013, we recorded impairment charges of $86 million primarily related to our Mari-B field, offshore Israel, due to natural field decline, and certain non-core onshore US properties divested during the year or held for sale at December 31, 2013. See Item 8. Financial Statements and Supplementary Data – Note 4. Asset Impairments.

4


United States
We have been engaged in crude oil and natural gas exploration and development activities throughout onshore US since 1932 and in the Gulf of Mexico since 1968. US operations accounted for 58% of 2013 total consolidated sales volumes and 55% of total proved reserves at December 31, 2013. Approximately 57% of the proved reserves are natural gas and 43% are crude oil, condensate and NGLs.
Sales of production and estimates of proved reserves for our US operating areas were as follows: 
 
 
Year Ended December 31, 2013
 
December 31, 2013
 
 
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)
DJ Basin
 
46

 
209

 
14

 
95

 
206

 
1,044

 
72

 
450

Marcellus Shale
 

 
139

 
1

 
24

 
1

 
1,374

 
22

 
252

Deepwater Gulf of Mexico
 
16

 
13

 
1

 
19

 
28

 
33

 
1

 
35

Other Onshore US
 
1

 
79

 

 
15

 
2

 
205

 

 
37

Total
 
63

 
440

 
16

 
153

 
237

 
2,656

 
95

 
774

Wells drilled in 2013 and productive wells at December 31, 2013 for our US operating areas were as follows: 
 
 
Year Ended December 31, 2013
 
December 31, 2013
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
DJ Basin
 
470

 
8,383

Marcellus Shale
 
117

 
284

Deepwater Gulf of Mexico
 
2

 
13

Other Onshore US
 
23

 
3,632

Total
 
612

 
12,312

(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.

5


 Locations of our onshore US operations as of December 31, 2013 are shown on the map below:

DJ Basin With the advent of horizontal drilling technology, the DJ Basin is now recognized by many industry analysts as a premier US crude oil resource play and is a key driver of our production and cash flow growth. It is our largest onshore US field (approximately 730,000 net acres), split between approximately 609,000 net acres in Colorado (approximately 96% operated working interest) and approximately 121,000 net acres in Wyoming (the majority non-operated). We have an extensive inventory of development drilling opportunities and plan to invest approximately 40% of our 2014 capital investment program in the DJ Basin.
The DJ Basin contributed an average of 95 MBoe/d of sales volumes, representing approximately 36% of total consolidated sales volumes in 2013, with approximately 63% being crude oil and NGLs, and represented approximately 32% of total proved reserves at December 31, 2013.
DJ Basin Acreage Exchange In October 2013, we closed an acreage exchange agreement with another operator related to our position in the DJ Basin. We exchanged approximately 50,000 net acres which consolidates our acreage position providing the opportunity to optimize drilling, production, and gathering activities and increase the number of extended-reach lateral wells in our development program. A short-term reduction in production of approximately 8 MBoe/d for fourth quarter 2013 related to the acreage exchange is anticipated to be quickly offset with operational efficiencies and cost savings. The transaction was accounted for at net book value, with no gain or loss recognized. We received $105 million in cash related to reimbursement of capital expenditures and other normal closing adjustments from the effective date of January 1, 2013, to closing date. See Item 8. Financial Statements and Supplementary Data – Note 3. Property Transactions.
2013 Activity Over the past year, we have focused our drilling and development activity on Integrated Development Plan (IDP) areas. This approach allows us to consolidate processing and handling infrastructure across large areas (typically 30,000 to 60,000 acres). With this approach, we construct multi-well horizontal drilling pads and centralized processing facilities (CPFs) to minimize our surface use. The drilling pads and CPFs facilitate efficient execution and operations by reducing our land surface and water usage while enabling us to efficiently gather and process crude oil, natural gas, and water from a large surrounding area, and reducing truck traffic and our overall surface footprint. We sanctioned the Wells Ranch IDP in 2012, and brought online our first CPF at Wells Ranch during the fourth quarter of 2013. In 2013, we sanctioned the East Pony IDP in northern Colorado and expect to sanction additional IDPs over the next several years. In the second half of 2014, we will begin operation of the Keota plant, our second natural gas processing plant in northern Colorado, to support our East Pony IDP along with future IDPs in the area. This will enhance our ability to continue development in this part of the Basin.

6


Also during 2013, we spud a total of 295 development wells, of which 291 were horizontal wells in the Niobrara and Codell formations. We continue to evaluate impacts of changes in well spacing and pad design. The well numbers above include 34 extended-reach (over 5,000 feet) lateral wells. We also participated in approximately 170 non-operated development wells during 2013.
In conjunction with our IDP approach, infrastructure in the area continues to be built out. Several infrastructure projects will come online over the next year and will significantly improve our flow assurance and reduce truck traffic. In the fourth quarter of 2013, a new crude oil gathering pipeline began operations. The new pipeline allows us to move crude oil from the northern parts of the field to several oil processing facilities and transportation hubs, with additional access to end markets. Additionally, a new rail facility commenced operations during the fourth quarter of 2013 to further enhance the transportation of our crude oil out of the field.
Our 2013 DJ Basin development program resulted in additions to proved reserves of approximately 153 MMBoe, approximately 67% of which are crude oil and NGLs.
Marcellus Shale   The Marcellus Shale represents our second onshore US core area. We have a 50-50 joint development agreement with CONSOL Energy Inc. (CONSOL) in approximately 700,000 gross acres in southwest Pennsylvania and northwest West Virginia, including approximately 90,000 gross acres recently acquired to expand our acreage position in northwest West Virginia to further optimize the value of our existing acreage position. We operate the wet gas (natural gas containing more liquid hydrocarbons) development area while CONSOL operates the dry gas (natural gas containing less liquid hydrocarbons) development area.
The Marcellus Shale contributed an average of 139 MMcfe/d of sales volumes and represented approximately 9% of total consolidated sales volumes in 2013 and approximately 18% of total proved reserves at December 31, 2013.
During 2013, we and CONSOL drilled 71 wet gas wells and 46 dry gas wells and brought online 35 wet gas wells and 18 dry gas wells.
Utilizing an IDP concept, modeled after the DJ Basin, we have begun to realize cost efficiencies through longer lateral wells and increased production growth through applied learning, completion design and optimized well placement. The current identified IDP areas are Majorsville, Southwest Pennsylvania Area Dry, and Allegheny County Airport.
Majorsville is the first operated IDP area, which came online in 2013 and will be the IDP model for the Marcellus Shale. It is in the core operating area with water and marketing infrastructure in place to support further development.
Based on our 2014 joint development plan, we expect to invest approximately 20% of our 2014 capital investment program in the Marcellus Shale.
Northeast Nevada Exploration Prospect   We have an active global new venture process focused on identifying additional exploration opportunities with reasonable entry cost, significant running room and the potential to become a new core area. In the onshore US, this effort has captured a 370,000 net acre position (66% fee acreage and remainder federal acreage) in northeast Nevada, prospective for crude oil exploration, which we identified through basin scale reconnaissance and innovative geoscience concepts. Based on acquired 3D seismic data over portions of the acreage, we began our exploratory drilling program with two exploratory wells drilled in 2013. We are currently evaluating the drilling results.
Other Non-Core 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) and Powder River Basin (north/central Wyoming); and Gulf Coast including the Haynesville field (East Texas and North Louisiana), Comanche Plains field (West Texas). Other non-core onshore properties accounted for 6% of total consolidated sales volumes in 2013 and 3% of total proved reserves at December 31, 2013. During 2013, we sold various 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.

7


Deepwater Gulf of Mexico   Locations of our operations in the deepwater Gulf of Mexico as of December 31, 2013 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 five 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 7% of total consolidated sales volumes in 2013 and 2% of total proved reserves at December 31, 2013.
We currently hold leases on 121 deepwater Gulf of Mexico blocks, representing approximately 52,000 net developed acres and approximately 409,000 net undeveloped acres. We are the operator on approximately 68% of our leases. See also Developed and Undeveloped Acreage – Future Acreage Expirations, below. During 2013, we sanctioned two major development projects in the deepwater Gulf of Mexico, Gunflint and Big Bend. See details below.
Deepwater Gulf of Mexico Exploration Program   Our deepwater Gulf of Mexico operations resulted from lease acquisition, expansion of our 3D seismic database, and an active drilling program. We currently have an inventory of 20 identified prospects, which are a combination of both high impact subsalt prospects and smaller, high value tie-back opportunities. The prospects are subject to an ongoing 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 the third quarter of 2014. The Atwood Advantage drillship is currently mobilizing to the Gulf of Mexico. It will be used in the 2014 drilling plan which includes various exploration, appraisal and well completion activities.
Our most significant deepwater Gulf of Mexico properties and current development plans are discussed in more detail below.
Rio Grande (Mississippi Canyon Block 698, 699, 738 and 782) The Rio Grande area is a co-development opportunity for recent exploration successes in the deepwater Gulf of Mexico. Big Bend (54% operated working interest) is a 2012 crude oil discovery, Troubadour (60% operated working interest) is a 2013 natural gas discovery, and Dantzler (45% operated working interest) is a 2013 crude oil discovery. In October 2013, we sanctioned the development plan for Big Bend utilizing a subsea

8


tieback to a third party host facility, with first production targeted for late 2015. We are currently evaluating possible integration of the Dantzler, potentially a 2014 sanctioned project, and Troubadour discoveries into our Rio Grande development plans.
Gunflint (Mississippi Canyon Block 948; 26% operated working interest) Gunflint is a 2008 crude oil discovery. During 2013, we completed drilling our second appraisal well and sanctioned the development plan for Gunflint utilizing a subsea tieback to an existing host facility. First production from Gunflint is targeted for 2016.
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. The Galapagos development began producing in 2012 and is connected to existing infrastructure through subsea tiebacks.
Other Offshore Properties   
Raton (Mississippi Canyon Block 248; 67% operated working interest) is a 2006 natural gas discovery and has been producing since 2008. South Raton (Mississippi Canyon Block 292; 79% operated working interest) is a 2008 crude oil discovery and began producing in 2012. Both Raton and South Raton are currently shut-in due to mechanical issues. We are currently awaiting access to the third party processing platform to begin remediation efforts on the South Raton well.
Swordfish (Viosca Knoll Blocks 917, 961 and 962; 85% operated working interest) is a 2001 crude oil discovery and began producing in 2005. The Swordfish project currently includes two producing wells. We recently acquired the Neptune Spar, a floating offshore production platform, which will process our remaining Swordfish production.
Ticonderoga (Green Canyon Block 768; 50% non-operated working interest) is a 2004 crude oil discovery and began producing in 2006. The project currently includes four producing wells, including one drilled in 2013. 
Lorien (Green Canyon Block 199; 60% operated working interest) is a 2003 crude oil discovery and began producing in 2006. The project currently includes one producing well.
Other offshore properties are connected to existing infrastructure through subsea tiebacks.
International
Our international business focuses on offshore opportunities in a number of countries and provides diversity to our portfolio. Development projects in Equatorial Guinea and Israel have contributed substantially to our growth over the last decade.
During 2013, we successfully brought the Tamar project, offshore Israel, and Alen project, offshore Equatorial Guinea, to production as we continue to advance our major development projects. Additionally, significant 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 expect these large acreage positions in West Africa and the Eastern Mediterranean will provide further exploration opportunities.
International operations accounted for 42% of total consolidated sales volumes in 2013 and 45% of total proved reserves at December 31, 2013. International proved reserves are approximately 84% natural gas and 16% crude oil and condensate. Based on our current 2014 capital investment program, we expect to invest approximately 20% of our 2014 capital investment program in international locations.
Operations in China, Cyprus, Equatorial Guinea, and Sierra Leone are conducted in accordance with the terms of production sharing contracts (PSCs). In Cameroon, we operate in accordance with the terms of a PSC and a mining concession. Operations in Israel, Nicaragua, the Falkland Islands, the North Sea, and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors.

9


Locations of our international operations as of December 31, 2013 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, 2013
 
December 31, 2013
 
 
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
 
32

 
252

 

 
73

 
94

 
691

 
209

Israel
 

 
209

 

 
35

 
3

 
2,479

 
416

China
 
4

 

 

 
4

 
6

 
2

 
6

Total International
 
36

 
461

 

 
112

 
103

 
3,172

 
631

Equity Investee
 
2

 

 
6

 
8

 

 

 

Discontinued Operations (North Sea)
 
1

 
2

 

 
1

 
1

 

 
1

Total
 
39

 
463

 
6

 
121

 
104

 
3,172

 
632

Equity Investee Share of Methanol Sales (MMgal)
 
 

 
155

 
 

 
 

 
 


Wells drilled in 2013 and productive wells at December 31, 2013 in our international operating areas were as follows:
 
 
Year Ended December 31, 2013
 
December 31, 2013
 
 
Gross Wells Drilled
or Participated in (1)
 
Gross Productive
Wells
International
 
 
 
 
Equatorial Guinea
 

 
24

Israel
 

 
7

North Sea
 

 
6

China
 
3

 
30

Nicaragua
 
1

 

Total International
 
4

 
67

(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.

10


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 blocks offshore Sierra Leone. Equatorial Guinea, the only producing country in our West Africa segment, accounted for approximately 28% of 2013 total consolidated sales volumes and 15% of total proved reserves at December 31, 2013. We held approximately 118,000 net developed acres and 80,000 net undeveloped acres in Equatorial Guinea, 695,000 net undeveloped acres in Cameroon, and 414,000 net undeveloped acres in Sierra Leone at December 31, 2013.
Locations of our operations in West Africa as of December 31, 2013 are shown on the map below:
Alen Project   Alen, our second major operated development project in West Africa, is a natural gas and condensate field primarily on Block O (45% operated working interest), offshore Equatorial Guinea. Alen began production in the second half of 2013, ahead of the original target start up date, and utilizes the Aseng FPSO for storage and offloading. Alen exited 2013 with production of 28 MBbl/d, and peak production of 30 to 35 MBbl/d is expected in 2014.
Aseng Project Aseng is a crude oil field on Block I (40% operated working interest), offshore Equatorial Guinea, which includes five horizontal wells flowing to the Aseng FPSO. Aseng started production in late 2011. 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.
The Aseng FPSO is designed to act as an oil production hub, as well as liquids storage and offloading facility, with capabilities to support future subsea oil field developments in the area. It also has the ability to process and store condensate from natural gas condensate fields in the area, the first of which is Alen. It is capable of processing 120 MBbl/d of liquids, including 80 MBbl/d of oil, and reinjection of up to 160 MMcf/d of natural gas. The Aseng FPSO has storage capacity of approximately 1.6 MMBbls of liquids. During 2013, Aseng maintained reliable and safe performance and averaged almost 99% production uptime.
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 gross metric tons per day. 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.
The execution phase of the Alba field B3 compression project began in early 2013 with an anticipated completion date in 2016.

11


Other Block O & I Projects    We are continuing our exploration and appraisal efforts offshore Equatorial Guinea. During the second half of 2013, we successfully drilled the Diega I-8 appraisal well, and we are targeting to sanction a development project in 2014, with first production targeted for 2016.
We continue to review the drilling results of the Carla O-7 and the Carla I-7 wells and evaluate regional development scenarios for the Carla discovery.
West Africa Gas Project    We have a natural gas development team working with Equatorial Guinea's Ministry of Mines, Industry and Energy to evaluate several monetization options for natural gas in the region.
Cameroon    We have an interest in over one million gross undeveloped acres offshore Cameroon, which include the YoYo mining concession (50% operating working interest) and Tilapia PSC (66.67% operating working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options.
Sierra Leone We participate in two offshore exploration blocks, SL 8A-10 and SL 8B-10, covering almost 1.4 million gross undeveloped acres. Under the terms of the award, Chevron (SL) Ltd. is the operator and we have a non-operated 30% working interest. During 2013, we acquired and began processing 766 square miles of 2D seismic information over portions of the acreage to assist with our 3D seismic plans.
Eastern Mediterranean (Israel and Cyprus)    The Eastern Mediterranean is one of our core operating areas, where we have had eight consecutive natural gas discoveries in recent years. We plan to explore for additional natural gas prospects as well as for crude oil, which may exist at greater depths in the basin.
Israel, the only producing country in our Eastern Mediterranean core area, accounted for 13% of 2013 total consolidated sales volumes and 30% of total proved reserves at December 31, 2013. Our leasehold position in the Eastern Mediterranean includes four leases and seven licenses offshore Israel and one license offshore Cyprus, and we are the operator of the properties at December 31, 2013. We held approximately 80,000 net developed acres and 326,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. The license offshore Cyprus covers approximately 596,000 net undeveloped acres adjacent to our Israel acreage.
Locations of our operations in the Eastern Mediterranean as of December 31, 2013 are shown below:  
Domestic Natural Gas Demand As the Israeli economy continues to grow, so does the demand for natural gas, 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 of natural gas will be available and are now investing the capital necessary to convert facilities to use natural gas. We expect that government requirements for emissions reductions could also drive incremental demand for natural gas as a fuel in the future.

12


Natural Gas Export As discussed below, we have made significant natural gas discoveries in the Eastern Mediterranean. We expect that these discoveries can be used to satisfy growing domestic demand as well as provide significant export potential. Eastern Mediterranean export projects would be well positioned to supply growing regional and global natural gas demand, and, as discussed further below, we are considering multiple development options. The government of Israel recently finalized an export policy. See Regulations – Update on Israel's Natural Gas Policy, below.
Tamar Natural Gas Project   Just over four years from discovery, the Tamar project began production in March 2013 and is now fully operational and delivering significant volumes of natural gas to Israel. The natural gas flows from the Tamar field through the world's longest subsea tieback, more than 90 miles to the Tamar platform, and then to the Ashdod onshore terminal (AOT). Tamar is a technical and commercial milestone that significantly contributes to our production growth. Production from Tamar averaged 153 MMcf/d, net, for the year with capable peak flow rates of approximately 1.0 Bcf/d gross to support seasonal high demand periods.
During 2013, we sanctioned the Tamar expansion project, which is estimated to grow our AOT capacity by 200 MMcf/d with operational start-up in the second half of 2015. Additionally, we are targeting the Tamar facility for further expansion up to 1.5 Bcf/d of capacity in 2016.
The Tamar partners have executed numerous gas sale and purchase agreements (GSPAs) for the initial and expanded capacity. See International Marketing Activities and Delivery Commitments, below.
Tamar Southwest During the second half of 2013, we drilled the successful Tamar Southwest natural gas exploratory well. Tamar Southwest, which was drilled to a total depth of 17,420 feet in 5,405 feet of water, is our eighth consecutive discovery in the Levant Basin. The field is located approximately eight miles southwest of the Tamar field. We operate Tamar Southwest with a 36% working interest, and we anticipate first production in 2015 utilizing Tamar infrastructure as part of our expansion project to meet domestic demand. Tamar Southwest will also provide flow rate assurance for our overall Tamar project.
Leviathan Natural Gas Project   In December 2010, we announced a significant natural gas discovery at the Leviathan-1 well 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. We own a 39.66% working interest in Leviathan. In 2013, the successful results from our recent Leviathan-4 appraisal well enhanced our understanding of the reservoir, and we continue our evaluation of multiple development concepts. Due to Leviathan's size, full field development is expected to require several development phases.
The Leviathan Phase 1 development concept is likely to serve both domestic demand and export. Domestic production could begin as early as 2017. We and our Leviathan partners recently signed a GSPA to sell approximately 170 Bcf of natural gas over a 20-year period to the Palestine Power Generation Company (PPGC). PPGC plans to build a power plant in the West Bank.
Multiple export options, including pipeline, onshore LNG, and floating LNG 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 We and our Leviathan partners continue working with Woodside Energy Ltd. (Woodside) to reach a definitive agreement to sell portions of our working interests in the Leviathan licenses to Woodside. Such an agreement would be subject to customary government approvals. Noble expects to convey a 9.66% working interest, reducing our working interest in the Leviathan licenses to 30%. Noble would continue as upstream operator.
Cyprus  During the second half of 2013, we drilled the successful Cyprus A-2 appraisal well on Block 12, offshore Cyprus. The A-2 well was drilled to a total depth of 18,865 feet in 5,575 feet of water and encountered approximately 120 feet of net natural gas pay within the targeted Miocene-aged sand intervals. We anticipate additional appraisal activities to further refine the ultimate recoverable resources and optimize field development planning. In addition to the appraisal well, we completed the acquisition phase of a 3D seismic study and are currently processing the results. We are the operator on Block 12 and hold a 70% working interest.
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 pressures 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 have integrated the data from the Leviathan-1 Deep well into our model to update our analysis and design a drilling plan specifically for a potential test of the deep oil concept.
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. In order to help meet Israeli natural gas demand prior to the commencement of Tamar production, we completed the Noa (47% operated working interest) and Pinnacles (47% operated working interest) wells and tied them back to the Mari-B platform in 2012. During 2013, we ramped down production from these fields when Tamar commenced production.

13


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 Karish (47.06% operated working interest), Dolphin (39.66% operated working interest) and Tanin 1 (47.06% operated working interest) natural gas discoveries. See Regulations – Update on Israel's Natural Gas Economy.
Other International
Our other international operations accounted for 1% of our total consolidated sales volumes for 2013 and less than 1% of total proved reserves at December 31, 2013.
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 gross acres located south and east of the Falkland Islands. Under the agreement, we have farmed-in to the Northern and Southern Area Licenses for a 35% working interest.
In March 2013, we assumed operatorship of the Northern Area License from FOGL. In January 2014, we assumed operatorship of the Southern Area License, pending governmental approval. We continue to process recently acquired 3D seismic information for the Southern Area License and began acquisition of 3D seismic information for the Northern Area License in late 2013. The construction of our shore base facility is ongoing in preparation for our first operated exploratory well which we expect to drill in 2015.
During fourth quarter 2012, FOGL drilled the Scotia exploratory well, which reached its Cretaceous objective and encountered 40 feet of net pay. Although we did not see a substantial amount of the reservoir section, virtually all sandstones with significant porosity in and below the target area contained hydrocarbons. Integration of well results with the 3D seismic information we are acquiring will allow us to assess the economic viability of this prospect.
Nicaragua During the second half of 2013, we transferred a portion of our working interests in acreage offshore Nicaragua, pending government approval, to two new partners, reducing our working interest to 70%. Additionally, we drilled the Paraiso-1 exploratory well, the first deepwater well drilled offshore Nicaragua. The Paraiso-1 did not encounter commercial quantities of hydrocarbons. However, the information gathered from this well will be integrated into our regional geologic model to help us assess the remaining exploration potential over our nearly two million gross acre position offshore Nicaragua.
China   We have been engaged in exploration and development activities in China since 1996 under the terms of a PSC, expiring in 2018. We have a 57% non-operated working interest in the Cheng Dao Xi field, which is located in the shallow water of the southern Bohai Bay.
We are currently negotiating for the sale of our China properties and expect the transaction to close during the first half of 2014. As of December 31, 2013, our China properties are included in assets held for sale in our consolidated balance sheet.
North Sea   During 2013, we sold substantially all of the non-operated working interest properties located in the UK and Netherlands sectors of the North Sea. On a combined basis, the sales resulted in a $65 million gain based on net sales proceeds of $56 million for the fields, and we continue to market our remaining North Sea properties. The North Sea's fourth quarter production was 600 Boe/d.
As of December 31, 2013, all the properties remaining in our North Sea geographical segment are included in assets held for sale in our consolidated balance sheet. Our consolidated statements of operations have been reclassified for all periods presented to reflect the operations of our North Sea geographical segment as discontinued.
See Item 8. Financial Statements and Supplementary Financial Data – Note 3. Property Transactions.
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 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;
fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis, 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.

14


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 Senior Vice President – Corporate Development and certain members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, new ventures, strategic planning, environmental analysis and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 33 years of industry experience with positions of increasing responsibility in engineering, evaluations, and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation   The SEC’s reserves rules allow the 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 2013 reserves estimates.
Third-Party Reserves Audit   In each of the years 2013, 2012, and 2011, we retained NSAI to perform reserves audits of proved reserves. The reserves audit for 2013 included a detailed review of nine of our major onshore US, deepwater Gulf of Mexico and international fields, which covered approximately 74% of US proved reserves and 98% of international proved reserves (85% of total proved reserves). The reserves audit for 2012 included a detailed review of eight of our major fields and covered approximately 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.
In connection with the 2013 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, 2013, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s report is attached as Exhibit 99.1 to this Annual Report on Form 10-K.
The fields audited by NSAI are chosen in accordance with Company guidelines and result in the audit of a minimum of 80% of our total proved reserves. The fields are chosen by the Senior Vice President – Corporate Development 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 fields that meet a minimum reserve quantity threshold, newly sanctioned development projects, and certain fields selected on a rotational basis.
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, 2013, on a quantity basis, the NSAI field estimates ranged from 21 MMBoe or 8% above to 15 MMBoe or 5% below as compared with our estimates on a field-by-field basis. Differences between our estimates and those of NSAI are reviewed for accuracy but are not further analyzed unless the aggregate variance is greater than 10%. Reserves differences at December 31, 2013 were, in the aggregate, approximately 9 MMBoe, or 1%.

15


Proved Undeveloped Reserves (PUDs)   As of December 31, 2013, our PUDs totaled 206 MMBbls of crude oil, condensate and NGLs and 2.1 Tcf of natural gas, for a total of 557 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, 2013:
227 MMBoe in the DJ Basin. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves over an approximate three-year period;
177 MMBoe in the Marcellus Shale. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling activity, we expect these PUDs to be converted to proved developed reserves over an approximate two-year period;
20 MMBoe in the deepwater Gulf of Mexico;
58 MMBoe in the Alba field, offshore Equatorial Guinea, 55 MMBoe of which have been recorded as PUDs for over five years and are attributable to a sanctioned compression project, for which construction has commenced. These volumes, which will be recovered through existing wells, will be reclassified to proved developed at start-up, currently expected in 2016; and
72 MMBoe in Israel primarily in the Tamar and Tamar Southwest fields.
The above fields represent 99% of total PUDs. The remaining 1% is associated with ongoing developments in various areas scheduled to be drilled in the next five years. PUDs include no material amounts, except the Alba field PUDs, which have remained undeveloped for five years or more since initial disclosure.
Changes in PUDs    Changes in PUDs that occurred during the year were due to:
 
 
United
 States
 
Equatorial
Guinea
 
Israel
 
China
 
Total
(MMBoe)
 
 
 
 
 
 
 
 
 
 
Proved Undeveloped Reserves Beginning of Year
 
272

 
74

 
375

 
2

 
723

Revisions of Previous Estimates
 
41

 
8

 
2

 
(1
)
 
50

Extensions, Discoveries and Other Additions
 
153

 
3

 
30

 
1

 
187

Purchase of Minerals in Place
 
22

 

 

 

 
22

Conversion to Proved Developed
 
(63
)
 
(27
)
 
(335
)
 

 
(425
)
Proved Undeveloped Reserves End of Year
 
425

 
58

 
72

 
2

 
557

United States
positive revisions of 39 MMBoe, primarily due to increased recovery assumptions in the DJ Basin and Marcellus Shale as a result of better than expected performance from existing wells;
positive revisions of 2 MMBoe, primarily in the Marcellus Shale, due to changes in commodity prices;
additions of 81 MMBoe in the DJ Basin horizontal drilling program;
additions of 58 MMBoe in the Marcellus Shale horizontal drilling program;
additions of 14 MMBoe in the deepwater Gulf of Mexico due to recently sanctioned Gunflint and Big Bend projects;
purchases of 22 MMBoe related to acquisitions of additional Marcellus Shale acreage; and
conversion of 63 MMBoe into proved developed reserves attributable to ongoing development in the DJ Basin (19% of year end 2012 PUD volumes converted) and Marcellus Shale (30% of year end 2012 PUD volumes converted).
Equatorial Guinea
positive revisions of 8 MMBoe due to performance revisions for the Alba field;
additions of 3 MMBoe attributable to an infill location at the Alba field; and
conversion of 27 MMBoe due to start-up of the Alen field.
Israel
positive revisions of 2 MMBoe due to performance revisions for the Tamar field;
additions of 30 MMBoe in the recently discovered and sanctioned Tamar Southwest field; and
conversion of 335 MMBoe due to start-up of the Tamar field.
Development Costs    Costs incurred to advance the development of PUDs were approximately $1.0 billion in 2013, $1.8 billion in 2012, and $1.4 billion in 2011. A significant portion of costs incurred in 2013 related to the following development projects: horizontal Niobrara; Marcellus Shale; Alen; and Tamar, which were converted to proved developed reserves in 2013.
Estimated future development costs relating to the development of PUDs are projected to be approximately $3.2 billion in 2014, $2.1 billion in 2015, and $1.2 billion in 2016. Estimated future development costs include capital spending on major

16


development projects, some of which will take several years to complete. PUDs 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 2018.  PUDs associated with our Alba compression project are also expected to be converted to proved developed reserves prior to the end of 2018.  Initial production from these PUDs is expected to begin during the years 2014 - 2018.
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, 2013, no crude oil or natural gas reserves information has been filed with, or included in any report to, any federal authority or agency other than the SEC and the Energy Information Administration (EIA) of the US Department of Energy. We file Form 23, including reserves and other information, with the EIA.


17


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, 2013
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
DJ Basin
 
46

 
209

 
14

 
$
93.28

 
$
3.50

 
$
36.33

 
$
4.71

Marcellus Shale
 

 
139

 
1

 
79.62

 
3.67

 
30.92

 
2.80

Other US
 
17

 
92

 
1

 
105.56

 
3.44

 
31.73

 
13.99

Total US
 
63

 
440

 
16

 
96.53

 
3.54

 
35.53

 
6.47

Equatorial Guinea
 
32

 
252

 

 
107.48

 
0.27

 

 
3.96

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 

 
153

 

 

 
5.32

 

 
2.61

  Other Israel
 

 
56

 

 

 
4.22

 

 
6.79

  Total Israel
 

 
209

 

 

 
5.02

 

 
3.73

China
 
4

 

 

 
103.21

 

 

 
9.45

Total Consolidated Operations
 
99

 
901

 
16

 
100.29

 
2.97

 
35.53

 
$
5.46

Equity Investee (3)
 
2

 

 
6

 
105.37

 
 
 
68.12

 
 
Total Continuing Operations
 
101

 
901

 
22

 
$
100.38

 
$
2.97

 
$
43.90

 
 
Year Ended December 31, 2012
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 

 
 
 
 
 
 
 
 
DJ Basin
 
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
 
 

 
 

 
 

 
 

 
 

 
 

 
 

DJ Basin
 
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

 
 

(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.

18


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, 2013, our operated properties accounted for the majority 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, 2013 was as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
6,376

 
5,848.5

 
5,936

 
4,647.6

 
12,312

 
10,496.1

Equatorial Guinea
 
5

 
2.0

 
19

 
7.1

 
24

 
9.1

Israel
 

 

 
7

 
2.7

 
7

 
2.7

North Sea
 
5

 
0.7

 
1

 
0.2

 
6

 
0.9

China
 
29

 
16.5

 
1

 
0.6

 
30

 
17.1

Total
 
6,415

 
5,867.7

 
5,964

 
4,658.2

 
12,379

 
10,525.9

 
Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of gross wells is the total number of wells in which a working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above.
 
Developed and Undeveloped Acreage   Developed and undeveloped acreage (including both leases and concessions) held at December 31, 2013 was as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
 
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
United States
 
 
 
 
 
 
 
 
Onshore
 
1,613

 
1,074

 
1,458

 
933

Offshore
 
115

 
52

 
575

 
409

Total United States
 
1,728

 
1,126

 
2,033

 
1,342

International
 
 

 
 

 
 

 
 

Equatorial Guinea
 
284

 
118

 
180

 
80

Falkland Islands
 

 

 
9,921

 
3,472

Cameroon
 

 

 
1,084

 
695

Israel
 
185

 
80

 
752

 
326

Cyprus
 

 

 
852

 
596

North Sea
 
6

 
1

 
20

 
4

China
 
7

 
4

 

 

Sierra Leone
 

 

 
1,380

 
414

Nicaragua
 

 

 
1,923

 
1,346

Total International
 
482

 
203

 
16,112

 
6,933

Total
 
2,210

 
1,329

 
18,145

 
8,275

 
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. 

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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. No material quantities of PUD reserves were associated with the expiring acreage.
 
 
Year Ended December 31,
 
 
2014
 
2015
 
2016
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
(thousands of acres)
 
 
 
 
 
 
 
 
 
 
 
 
Onshore US (1)
 
321

 
205

 
306

 
153

 
272

 
219

Deepwater Gulf of Mexico
 
20

 
14

 
42

 
40

 
81

 
50

Equatorial Guinea
 
55

 
19

 

 

 

 

Israel (2)
 
691

 
303

 

 

 

 

Cyprus (2)
 
852

 
596

 

 

 

 

Cameroon (3)
 

 

 
458

 
305

 

 

Total
 
1,939

 
1,137

 
806

 
498

 
353

 
269


(1) 
Represents acreage that will expire if no further action is taken to extend. Approximately 52% 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. See also Regulations - Update on Israel Natural Gas Policy.
(3) 
The acreage in Cameroon is comprised of our Tilapia PSC and YoYo mining concession. Pursuant to the Tilapia PSC, our second exploration period expires on July 6, 2015; however, we have the right to extend our acreage for an additional two years. Pursuant to our YoYo mining concession, development must commence prior to December 2014, and 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, 2013
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 
5.8

 

 
5.8

 
341.7

 
3.9

 
345.6

 
351.4

Equatorial Guinea
 

 

 

 

 

 

 

China
 

 

 

 
1.7

 

 
1.7

 
1.7

Nicaragua
 

 
0.7

 
0.7

 

 

 

 
0.7

Total
 
5.8

 
0.7


6.5


343.4


3.9


347.3


353.8

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

 

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In addition to the wells drilled and completed in 2013 included in the table above, wells that were in the process of drilling or completing at December 31, 2013 were as follows: 
 
 
Exploratory (1)
 
Development(2)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
10

 
5.6

 
188

 
106.8

 
198

 
112.4

Cameroon
 
1

 
0.5

 

 

 
1

 
0.5

Cyprus
 
2

 
1.4

 

 

 
2

 
1.4

Equatorial Guinea
 
9

 
4.2

 

 

 
9

 
4.2

Falkland Islands
 
1

 
0.4

 

 

 
1

 
0.4

Israel
 
8

 
3.3

 


 


 
8

 
3.3

Total
 
31

 
15.4

 
188

 
106.8

 
219

 
122.2


(1) 
Includes exploratory wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
(2) 
Includes wells pending completion activities.

See Item 8. Financial Statements and Supplementary Financial Data - Note 6. Capitalized Exploratory Well Costs for additional information on suspended exploratory wells.
Oil Spill Response Preparedness  In the US, 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 exploratory 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 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 15,000 psi-gauge and 10,000 psi-gauge intervention capping stacks designed to shut-in wells in water depths to 10,000 feet. We have entered into a separate utilization agreement with HESG which specifies the asset day rates should the HFRS system be deployed.
In May 2013, we successfully led a full-scale drill deployment of critical well control equipment to assess our ability to respond to a potential subsea blowout in the deepwater Gulf of Mexico. The drill was a collaborative test between the Department of the Interior's Bureau of Safety and Environmental Enforcement (BSEE), the US Coast Guard, Louisiana Offshore Coordinator's Office and all 15 member companies of the HWCG consortium. Activation of the HFRS rapid response system and deployment of the HWCG capping stack to pressurization requirements met all objectives and marked the successful completion of the exercise.
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 Holdings Inc. (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.
In June 2013, we conducted a Full Scale Oil Spill Response exercise offshore Israel with participation from Israel’s Ministry of Environmental Protection, Ministry of Energy and Water Resources, Ministry of Transportation, and Ministry of Defense. This exercise successfully demonstrated to the Israeli government our ability to deploy and manage resources in an emergency.
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.
Certain onshore US areas in which we operate have had minimal infrastructure in place for the processing and transportation of our production. Company and third party infrastructure projects coming online in the near future will improve flow assurance and enhance transportation of produced crude oil and natural gas to end markets.
International Marketing Activities   Our share of crude oil and condensate from the Aseng and Alen fields is sold to Glencore Energy UK Ltd (Glencore Energy) under a long-term sales contract through May 2015, at market rates, and is transported by tanker. 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. 
Natural gas from the Alba field is sold for $0.25 per MMBtu to a methanol plant, an LPG plant and an unaffiliated LNG plant. The sales contract with the methanol plant runs through 2026, and the sales contract with the LNG plant runs through 2023. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method of accounting.

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In Israel, we sell natural gas from the Tamar and Mari-B fields, and have agreements with multiple customers to sell natural gas under long-term contracts, ranging from 15 to 17 years. 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 through the end of the field's production life at market-based prices.
Delivery Commitments   Some of our natural gas sales contracts specify the delivery of fixed and determinable quantities.
Israel Gas Sales and Purchase Agreements (GSPA) We currently sell natural gas from our producing fields offshore Israel to the Israel Electric Corporation (IEC) and numerous other Israeli purchasers, including independent power producers, cogeneration facilities and industrial companies. 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 contracts are interruptible during certain contract periods. Sales prices may be based on an initial base price subject to price indexation over the life of the contract and with a floor. The IEC contract provides for price reopeners in the eighth and eleventh years with limits on the increase/decrease from the contractual price.
Under the contracts, 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. The cap is 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.
As of December 31, 2013, a total of approximately 6.2 Tcf, gross, (2.2 Tcf, net) of natural gas remained to be delivered under the contracts. At December 31, 2013, we have recorded 2.5 Tcf, net, of proved natural gas reserves, including 433 Bcf, net, of PUD reserves, for offshore Israel.
Significant Purchasers   Glencore Energy was the largest single non-affiliated purchaser of 2013 production and purchased our share of crude oil and condensate production from the Alba, Aseng and Alen fields in Equatorial Guinea. Sales to Glencore Energy accounted for 25% of 2013 total crude oil, natural gas and NGL sales, or 34% of 2013 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 DJ Basin area and internationally from the North Sea. Sales to Shell accounted for 13% of 2013 total crude oil, natural 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 2013. We maintain credit insurance associated with specific purchasers and 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   Although commodity prices are historically volatile, price changes were relatively mild in 2013. Prices for crude oil and natural gas are affected by a variety of factors beyond our control. We use derivative instruments 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 has been to hedge up to 50% of our forecasted hedgeable crude oil and natural gas production for the current year plus two additional calendar years. The limit was increased to up to a maximum of 75% of forecasted hedgeable global crude oil production for the years 2014 and 2015. We exercise strong management of our hedging program with strong oversight by our Board of Directors. For additional information, see Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk, and Item 8. Financial Statements and Supplementary Data – Note 8. Derivative Instruments and Hedging Activities
Regulations 
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 over time and frequently impose more stringent 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, that impose incremental costs to comply, and that carry substantial penalties for failure to comply. These laws, regulations and orders may restrict the rate of crude oil and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors.

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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 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 Energy, 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 eliminated, inter alia, a previously enacted progressive reduction in the corporate tax rate, and increased the corporate tax rate to 25%. The Israeli corporate tax rate was further increased from 25% to 26.5% as a part of the Budget Law 2013-2014, in 2013.
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 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. 
In 2009, the EPA launched a program that requires many suppliers of hydrocarbon 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 report their annual greenhouse gas (GHG) emissions. In November 2010, the EPA issued final regulations requiring such annual reporting of GHG emissions from qualifying facilities in the upstream oil and natural gas sector, including onshore production (Subpart W). The first annual reports under Subpart W were due in 2012 for 2011 emissions. Substantially all of our onshore US properties are subject to the Subpart W reporting requirements. Information in such reports could form the basis of future GHG regulations.
On August 16, 2012, the EPA issued New Source Performance Standards (NSPS) and National Emission Standards for Hazardous Air Pollutants to control air emissions associated with crude oil and natural gas production, including natural gas wells that are hydraulically fractured. These regulations require technologies and processes that, while reducing emissions, will 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 is intended to 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 natural gas wells will be required to use green completions. The EPA's final rules are expected to have minimal impact on our business. The reduction of GHG emissions 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 have undertaken emission reduction projects such as our US Vapor Recovery Unit (VRU) program, where we have installed VRUs to capture natural 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 (located in the DJ Basin). 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 approved new setback rules for oil and gas wells and production facilities located in close proximity to occupied buildings. Previously, the COGCC allowed setback distances of 150 feet in rural areas and 350 feet in high density urban areas. These have been increased to a uniform 500 feet statewide setback from occupied buildings and 1,000 feet from high occupancy building units. The new setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts to surface owners and the owners of occupied building units. In addition, the new rules 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. Those new statewide rules require 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. For the Greater Wattenberg Area, the rule requires operators to sample only one water well per quarter governmental section before drilling and between six to 12 months after completion.
On the environmental side, the Colorado Department of Public Health and Environment, under delegation from the EPA, has adopted measures to regulate air emissions, water protection and waste handling and disposal relating to our oil and gas

24


exploration and production. Moreover, the Colorado Department of Public Health and Environment has proposed extending the EPA’s air standards for oil and gas operations by directly controlling methane emissions.
In November 2013, the state of Colorado proposed rules to regulate detection and reduction of methane emissions associated with oil and gas drilling. The proposed rules, which would cover the life cycle of oil and gas development, production, and maintenance, reflect a collaborative effort by the Environmental Defense Fund, Noble Energy and other oil and gas operators.
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 drilling, completion, 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 Supreme Court upheld the lower court's decision, which could make it more difficult to develop our Marcellus Shale 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 any unintended 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.
Other Jurisdictions 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 where 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. Beyond that, in 2012, Longmont, Colorado prohibited the use of hydraulic fracturing. The oil and gas industry is challenging that ban, and the authority of local jurisdictions to regulate oil and gas development, in court. In November 2013, several other Colorado municipalities passed ballot measures supporting restrictions or bans on the practice of hydraulic fracturing within their boundaries. See Hydraulic Fracturing.
Update on Israel's Natural Gas Policy 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 harm, but rather promotes the needs of domestic users and encourages development of natural gas-based domestic industry. The recommendations included, among others, the following points:

25


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 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 Israeli 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.
On June 23, 2013, the Israeli government approved the main recommendations of the Committee with certain amendments, including a limitation on the exports allowed from the Tamar field (50% of uncontracted quantities). However, certain members of the Knesset, the Israeli parliament, demanded that natural gas policy, including exports, be legislated by the Knesset as opposed to a government decision. The legality of the government decision was appealed to the Israeli High Court of Justice (High Court). The High Court rejected the appeal on October 21, 2013.
Together with the approval of the Committee recommendations on June 23, 2013, the government has required the Ministry of Finance to submit recommendations on export pricing guidelines. The Ministry of Finance has established a work team, which includes representatives from the Tax Authority, the Budgets Department, and the Department of the Chief Economist. The work team was assigned with the aim of presenting a taxation model that will suit all types of export transactions in accordance with the principles detailed in the government resolution. In accordance with a Ministry of Finance notice, we and our partners have submitted several comprehensive responses to the work team and also conducted several follow-up meetings. The work team is expected to publish its recommendations in early 2014.
With our partners, we are continuing to study the official export and natural gas development policies and are monitoring any additional developments to assess the possible impact, positive or negative, of any resulting laws or regulations on our future development activities in Israel. Certain changes in Israel's fiscal and/or regulatory regimes or energy policies occurring as a result of Antitrust Authority rulings or government policy on natural gas development and/or exports could delay or reduce the profitability of our Tamar and/or Leviathan development projects, delay closing of a farm-out agreement which we and our partners are negotiating with Woodside or preclude such an agreement entirely, and/or render future exploration and development projects uneconomic.
Additionally, the Israeli Antitrust Commissioner (Commissioner) has been actively engaged to encourage competition in developing Israel's natural gas resources. The Commissioner ruled that all domestic natural gas sales contracts are subject to review and approval of the Antitrust Authority and has intervened regarding the terms used in long term contracts with certain gas customers. In addition, the Commissioner has initiated a hearing process to evaluate a contention that allegedly the original acquisition agreement for the Leviathan acreage is a restrictive arrangement. The Commissioner has publicly expressed concerns regarding ownership concentration in exploration blocks and development projects and its potential impacts on a competitive domestic natural gas market. We continue to engage with the Israeli government on this matter. Antitrust Commissioner decisions and actions could potentially result in a requirement to divest assets, reduce or relinquish revenue interests, and/or implement the marketing of our working interest share of production. We have cooperated with the Antitrust Authority's review and, at this time, cannot predict the outcome.
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, provides for federal oversight of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act mandates that the Commodities Futures Trading Commission (CFTC) adopt rules and regulations implementing the derivatives market provisions of the Dodd-Frank Act , including requirements that certain transactions be cleared on exchanges and that collateral (commonly referred to as “margin”) be posted for uncleared swaps and other derivatives transactions. Although there is an exception from swap clearing and trade execution requirements for commercial end-users that meet certain conditions (commonly referred to as the “end-user exception”), certain market participants, including most if not all of our counterparties, will be required to clear many of their swap transactions with entities that do not satisfy the end-user exception and will have to transact many of their swaps on swap execution facilities or designated contract markets, rather than over-the-counter on a bilateral basis.

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We have determined that we qualify as a ‘‘non-financial entity’’ for purposes of the end-user exception and satisfy the other requirements of the end-user exception. As a result, our hedging activity will not be subject to mandatory clearing. We do not expect to clear our swaps, and our swap transactions will not be subject to the margin requirements imposed by derivatives clearing organizations. Because the margin regulations for uncleared swaps have not been adopted, it is possible that the CFTC, in conjunction with prudential banking 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. These requirements may increase the cost to our counterparties of hedging the swap positions they enter into with us, and thus may increase our cost of entering into hedges, which could reduce 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. The changes in the regulation of swaps may also result in certain market participants deciding to curtail or cease their derivatives activities. While many regulations have been promulgated and are already in effect, the rulemaking and implementation process is ongoing, and the ultimate effect of the adopted rules and regulations and any future rules and regulations on our business cannot be determined at this time.
Impact of Dodd-Frank Act Section 1504 Section 1504 of the Dodd-Frank Act requires disclosure of certain payments made by resource extraction companies to a foreign government or the U.S. federal government for the commercial development of oil, natural gas or minerals. The Dodd-Frank Act mandates that the SEC promulgate rules to implement this disclosure requirement. On August 22, 2012, the SEC adopted Rule 13q-1 under the Exchange Act, which would have required resource extraction companies, such as us, to publicly file 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. That rule, however, was vacated by the District Court for the District of Columbia on the grounds that (i) the SEC misread the statute to require public filing of the information and (ii) the SEC erred in denying an exemption where foreign law prohibits disclosure of payments. The SEC declined to appeal the court’s decision and, instead, is expected to promulgate a revised rule that is responsive to the court’s holdings. We expect that the new rule proposal will be subject to a process of public notice and comment, which generally takes several months to complete, and will not become effective until after the publication of a final revised rule.
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 by prior owners or operators in accordance with current laws, 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 and may continue to do so. 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.
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. 

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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 and regulators. Concerns over potential hazards associated with the use of hydraulic fracturing and its impact on the environment and, potentially, the general public health, have been raised at all levels including US federal, state and local, as well as internationally. 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 since 1947, 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); a large proportion 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 we engage in recycling efforts in both the DJ Basin and Marcellus Shale. We believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the environment or general public health. 
Potential Rulemaking Although hydraulic fracturing is regulated primarily at the state level, governments and agencies at all levels from federal to municipal are conducting studies and considering regulations. For example, in 2011, the US Secretary of Energy formed the Shale Gas Production Subcommittee (Subcommittee), a subcommittee of the Secretary of Energy Advisory Board. The Subcommittee issued final recommendations in November 2011 that included better communications with the public, better air quality controls, 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.  
In 2012, the US BLM proposed regulations governing hydraulic fracturing on federal lands, which were withdrawn and then reissued in 2013.
Also 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 guidance outlines for EPA permit writers, where EPA is the permitting authority, requirements for diesel fuels used for hydraulic fracturing of wells, technical recommendations for permitting those wells, and a description of diesel fuels for EPA underground injection control permitting.
The EPA is also 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 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, several communities in Colorado became interested in increasing regulatory requirements on oil and gas development. The most notable situation occurred in the City of Longmont, Colorado where voters chose 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. The case is expected to go to trial in 2014.   
In the Colorado 2013 general election, the municipalities of Boulder, Broomfield, Fort Collins and Lafayette each passed ballot measures supporting restrictions or bans on the practice of hydraulic fracturing within their boundaries. The Broomfield election results are under review by State officials for potential voting irregularities. For other communities, the specific prohibitions and moratoria were effective upon passage. The large majority of our DJ Basin acreage is not located in these municipalities and, therefore, we do not expect our operations to be impacted by these developments. However, in the future, should additional Colorado ballot initiatives be undertaken to regulate, limit or ban hydraulic fracturing or other facets of oil and gas exploration, development or operations, our business could be impacted resulting in delay or inability to develop oil and gas reserves, reducing our long-term reserves, production and cash flow growth, and have a potential negative impact on our stock price.

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On May 16, 2013, the US Department of the Interior issued proposed rules governing hydraulic fracturing on federal lands. The proposed rules would affect drilling operations on the 700 million acres of federally-owned minerals administered by the BLM, as well as 56 million acres of Native American-owned minerals.
The proposed rules would require companies to:
disclose chemicals they inject by using an online database, with an exception for chemicals deemed to be trade secrets;
verify that wells are drilled properly so that toxic fluids do not contaminate groundwater; and
submit plans for managing drilling wastewater in lined pits or storage tanks.
The proposed rules could see further revision. Because oil and gas drilling and development activities, including hydraulic fracturing practices, are already regulated at the state level, compliance with federal hydraulic fracturing regulations may result in additional costs and reporting burdens.
In Nevada, the State Assembly recently adopted legislation that requires the development of a program to regulate the use of hydraulic fracturing in Nevada. State regulators are in the process of proposing rules and holding public hearings.
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, which requires companies to disclose, on a public registry, chemical ingredients used to hydraulically fracture wells. The registry, FracFocus.org, is 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. 
Additional Information  See: 
Items 1. and 2. Business and Properties – Regulations;
Item 1A. Risk Factors; 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 ongoing effort.
We begin by leasing acreage (or deepwater lease blocks) from individuals, other operators or the host government. It may take years for us to assemble sufficient 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 contract a drilling rig with the specifications for the depth and well pressures which we expect to drill.
For example, in 2009 we began acquiring our 370,000 fairly contiguous acreage position in northeast Nevada. It took over two years to assemble adequate acreage to warrant data collection. Once the acreage position had been established, we conducted extensive 3D seismic surveys and obtained other data, which our exploration staff analyzed and used to plan an initial drilling program. During 2013, we initiated an exploratory vertical well pilot program. Drilling locations were driven by analysis of the 3D seismic surveys. 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. In northeast Nevada, we expect to see results of our pilot well program by late 2014.
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. Appraisal or development drilling requires additional

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time to contract for an appropriate drilling rig, and obtain pipe, other equipment, and supplies. Due to the current strong onshore and offshore drilling activity, drilling rigs and hydraulic fracturing crews are in high demand, and there could be delays as we wait for rigs or crews to become available.
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 data 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 information 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. 
Geographical Data
We have operations throughout the world and manage our operations by region. 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, West Africa, Eastern Mediterranean, and Other International and Corporate. See Item 8. Financial Statements and Supplementary Data – Note 15. Segment Information
Employees 
Our total number of employees increased 15%, from 2,190 at December 31, 2012 to 2,527 at December 31, 2013, in support of our major development and exploration projects. The 2013 year-end employee count includes 248 foreign nationals working as employees in Israel, Cyprus, Equatorial Guinea, Cameroon, Nicaragua, and the UK. We regularly use independent contractors and consultants to perform various field and other services. 
Offices 
Our principal corporate office is located at 1001 Noble Energy Way, Houston Texas, 77070. We maintain additional offices in Houston, Texas; Ardmore, Oklahoma; Denver, Colorado; Greeley, Colorado; Canonsburg, Pennsylvania; Washington, D. C.; and in China, Cameroon, Equatorial Guinea, Israel, Cyprus, Nicaragua, Falkland Islands, the UK and the Netherlands. 
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.
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. Curative efforts for remaining uncured defects related to the Marcellus Shale acreage are ongoing. 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 include 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.

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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, cash flow at risk analysis, 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, a robust global compliance program, and government and community relations initiatives. 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.
Available Information
Our website address is www.nobleenergyinc.com. Available on this website under “Investors – 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. Copies of the Code of Conduct, 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, cash flows, 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 2013 were as follows:
 
 
Daily Average Settlement Price for Prompt Month Contracts
 
 
High
 
Low
Year Ended December 31, 2013
 
 
 
 
NYMEX
 
 
 
 
   Crude Oil - WTI (Per Bbl)
 
$
110.53

 
$
86.68

   Natural Gas - HH (Per MMBtu)
 
4.46

 
3.11

Brent
 
 
 
 
   Crude Oil (Per Bbl)
 
118.90

 
97.69

Prices for our US NGL production are determined at two primary market centers, Conway and Mt. Belvieu. For the year ended December 31, 2013, US average realized NGL prices were approximately 35% of average realized crude oil prices and tended to track the volatility of NYMEX WTI.

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The application of new drilling technologies in the US has unlocked significant crude oil resources in shale formations, resulting in increased domestic supply. This has resulted in US crude oil prices becoming disconnected from global crude oil price indices such as Brent. Current crude oil forward price curves indicate market expectations are that US oil is likely to continue trading at a discount to global prices.
In addition, changes may occur in regional US crude oil and natural gas markets with the markets moving from being undersupplied (premium prices) to being oversupplied (discounted prices). Regional US supply/demand changes could significantly impact netback charges and, ultimately, project economics. Finally, a current federal export ban on crude oil and/or governmental regulations regarding LNG exports could limit pricing as domestic supply increases.
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, in particular, US crude oil and NGL supply growth resulting from shale oil development;
Organization of Petroleum-Exporting Countries (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, natural gas, and NGLs;
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;
developments in 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;
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;
fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and its impacts on crude oil demand as a transportation fuel;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Declines in commodity prices or inadequate transportation and storage of our product may have the following effects on our business:
reduction of our revenues, operating income and cash flows;
curtailment or shut-in of our 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;
certain properties in our portfolio may become economically unviable;
delay or postponement of some of our capital projects;
significant reductions in our capital investment programs, resulting in a reduced ability to develop our reserves;
limitations on our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations;
limitations on our access to sources of capital, such as equity and debt; and
declines in our stock price.
In addition, lower commodity prices, including declines in the commodity forward price curves, may result in the following:
asset impairment charges resulting from reductions in the carrying values of our crude oil and natural gas properties at the date of assessment;
additional counterparty credit risk exposure on commodity hedges; or
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, and limit our growth with 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. We have expanded our horizontal drilling programs in the DJ Basin and Marcellus Shale and recently sanctioned deepwater development projects at Gunflint and Big Bend. Our Leviathan, Cyprus, Carla and Diega discoveries are being appraised and, as such, not yet sanctioned. It will take several years before first production is achieved.

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Some projects, such as crude oil and natural gas projects offshore West Africa and the Eastern Mediterranean, entail significant technical and other complexities including 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 or floating LNG infrastructure. Additionally, we have multiple unsanctioned integrated development plans for our onshore US acreage.
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 depend 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 a 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 which could adversely affect project development;
lack of government approval for projects;
civil disturbances, anti-development activities, legal challenges or other potential 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 42% of our 2013 total consolidated sales volumes coming from international areas. We are also conducting exploration activities in these and other international areas. Our operations may be adversely affected by political and economic developments, including the following:
renegotiation, modification or nullification of existing contracts, such as may occur pursuant to future regulations enacted as a result of changes in Israel's export and natural gas development policies, 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 host nations, such as expropriation or nationalization of assets or termination of contracts;
disruptions caused by territorial or boundary disputes in certain international regions;
changes in drilling or safety regulations in other countries as a result of the Deepwater Horizon Incident, a large oil spill occurring in the Gulf of Mexico in 2010, or other incidents that have occurred;
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; 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 offshore exploration activities, such as Cyprus, the Falkland Islands, or Nicaragua. 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 related government policies and regulations in the countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access along with government participation in oil and gas projects, royalties and taxes. 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 financial take from developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in the fiscal regimes of these countries could have a significant impact on our operations and financial performance. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws or the effect such interpretations could have on our business.

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Currently, many governments globally are seeking additional revenue sources, including, potentially, increases in government financial take from oil and gas projects. In developing nations, additional revenues may be sought to support infrastructure and economic development and for social spending. In many OECD (Organisation for Economic Cooperation and Development) nations, governments are facing significant budget deficits and growing national debt levels, as well as pressure from financial markets to address structural spending imbalances.
In the US, certain measures have been proposed that would alter current tax expense on oil and gas companies, for example: the repeal of percentage depletion for oil and natural gas properties; the deferral of expensing intangible drilling and development costs (IDC); the inability to expense costs of certain domestic production activities; and a lengthening of the amortization period for certain geological and geophysical expenditures. It is likely that some of these proposals to increase tax expense on the oil and gas industry will continue to be reviewed by the US Congress in 2014 or future years. The enactment of some or all of these proposals would have a significant negative impact on our capital investment, production and growth. In particular, we estimate that the elimination of the deductibility of IDC expenditures would impact our cash available for investment and could curtail our domestic capital spending program up to 20%.
Changes in fiscal regimes have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations in the following ways, among others:
restrict resource access or investment in lease holding;
reduce exploration activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
have a negative impact on the ability of us and/or our partners to obtain financing;
cause delay in or cancellation of development plans, which could also have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;
result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow;
restrict our ability to compete with imported volumes of crude oil or natural gas; and/or
adversely affect the price of our common stock.
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.
Violent acts resulting in loss of life, destruction of property, environmental damage and pollution occur around the world. Many incidents are driven by civil, ethnic, religious or economic strife. In addition, the number of incidents attributed to various terrorist organizations has increased significantly. We operate in regions of the world that have experienced such incidents or are in close proximity to areas where violence has occurred.
We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results, among others:    
volatility in global crude oil prices which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
negative impact on the world crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel or supplies to enter or exit the countries where we are conducting operations;
disruption of our operations due to evacuation of personnel;
inability to deliver our production due to disruption or closing of transportation routes;
reduced ability to export our production due to efforts of countries to conserve domestic resources;
damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
damage to or destruction of property belonging to our natural gas purchasers leading to interruption of gas deliveries, claims of force majeure, and/or termination of natural gas sales contracts, resulting in a reduction in our revenues;

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inability of our service and equipment providers to deliver items necessary for us to conduct our operations resulting in a halt or delay in our planned exploration activities, delayed development of major projects, or shut-in of producing fields;
lack of availability of drilling rig, oilfield equipment or services if third party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
Loss of property and/or interruption of our business plans resulting from civil unrest could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.
Concentration of our operations in a few core areas may increase our risk of production loss.
Our operations are concentrated in five core areas: the DJ Basin, the Marcellus Shale, and the deepwater Gulf of Mexico in the US, offshore West Africa, and the Eastern Mediterranean. These core areas provide approximately 95% of our current production, and account for approximately 90% of our 2014 capital investment program and most of our exploration potential.
In addition, a large portion of our production is from a relatively few deepwater wells. For example, approximately 40% of our 2013 production came from four offshore developments. Although, individually, none of the core areas represented more than 35% of our 2013 total sales volumes, disruption of our business in one of these areas, such as from an accident, natural disaster, government intervention, or other event, would result in a significant impact on our production profile, cash flows and overall business plan.
We do not maintain business interruption (loss of production) insurance for all of our assets. Loss of production or limitations on our access to reserves in one of our core operating areas could have a significant negative impact on our cash flows and profitability.
Exploration, development and production activities as well as natural disasters or adverse weather conditions could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil and natural gas, including:
injuries and/or deaths of employees, supplier personnel, or other individuals;
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
loss of product occurring as a result of transfer to a rail car or train derailments;
formations with abnormal pressures and basin subsidence;
release of pollutants;
surface spillage of, or contamination of groundwater by, fluids used in operations;
security breaches, cyber attacks, piracy, or terroristic acts;
theft or vandalism of oilfield equipment and supplies, especially in areas of active onshore operations;
hurricanes, cyclones, windstorms, or “superstorms” which could affect our operations in areas such as the Gulf Coast, deepwater Gulf of Mexico, Marcellus Shale, Eastern Mediterranean or offshore China;
winter storms and snow which could affect our operations in the DJ Basin and Marcellus Shale;
extremely high temperatures, which could affect third party gathering and processing facilities in the DJ Basin;
volcanoes which could affect our operations offshore Equatorial Guinea;
flooding which could affect our operations in low-lying areas;